U.S. patent application number 12/462266 was filed with the patent office on 2011-02-03 for drilling with a high pressure rotating control device.
This patent application is currently assigned to Weatherford/Lamb, Inc.. Invention is credited to Thomas F. Bailey, Don M. Hannegan, Carel W. Hoyer, Melvin T. Jacobs, Nicky A. White.
Application Number | 20110024195 12/462266 |
Document ID | / |
Family ID | 42671899 |
Filed Date | 2011-02-03 |
United States Patent
Application |
20110024195 |
Kind Code |
A1 |
Hoyer; Carel W. ; et
al. |
February 3, 2011 |
Drilling with a high pressure rotating control device
Abstract
A Drill-To-The-Limit (DTTL) drilling method variant to Managed
Pressure Drilling (MPD) applies constant surface backpressure,
whether the mud is circulating (choke valve open) or not (choke
valve closed). Because of the constant application of surface
backpressure, the DTTL method can use lighter mud weight that still
has the cutting carrying ability to keep the borehole clean. The
DTTL method identifies the weakest component of the pressure
containment system, such as the fracture pressure of the formation
or the casing shoe leak off test (LOT). With a higher pressure
rated RCD, such as 5,000 psi (34,474 kPa) dynamic or working
pressure and 10,000 psi (68,948 kPa) static pressure, the
limitation will generally be the fracture pressure of the formation
or the LOT. In the DTTL method, since surface backpressure is
constantly applied, the pore pressure limitation of the
conventional drilling window can be disregarded in developing the
fluid and drilling programs. Using the DTTL method a deeper
wellbore can be drilled with larger resulting end tubulars, such as
casings and production liners, than had been capable with
conventional MPD applications.
Inventors: |
Hoyer; Carel W.; (London,
GB) ; Hannegan; Don M.; (Fort Smith, AR) ;
Bailey; Thomas F.; (Houston, TX) ; Jacobs; Melvin
T.; (Fort Smith, AR) ; White; Nicky A.;
(Poteau, OK) |
Correspondence
Address: |
STRASBURGER & PRICE, LLP;ATTN: IP SECTION
1401 MCKINNEY, SUITE 2200
HOUSTON
TX
77010
US
|
Assignee: |
Weatherford/Lamb, Inc.
Houston
TX
|
Family ID: |
42671899 |
Appl. No.: |
12/462266 |
Filed: |
July 31, 2009 |
Current U.S.
Class: |
175/65 ; 166/319;
166/386 |
Current CPC
Class: |
E21B 21/08 20130101;
E21B 43/10 20130101; E21B 21/10 20130101; E21B 33/085 20130101;
E21B 47/06 20130101; E21B 21/085 20200501; E21B 36/001 20130101;
E21B 47/07 20200501; E21B 33/03 20130101; E21B 33/13 20130101; E21B
19/00 20130101; E21B 21/00 20130101 |
Class at
Publication: |
175/65 ; 166/319;
166/386 |
International
Class: |
E21B 4/02 20060101
E21B004/02; E21B 34/00 20060101 E21B034/00; E21B 33/12 20060101
E21B033/12 |
Claims
1. Method for drilling a wellbore in a formation with a fluid,
comprising the steps of: casing a portion of the wellbore using a
casing having a casing shoe; determining a casing shoe pressure;
determining a formation fracture pressure; positioning a rotating
control device with said casing; and drilling the wellbore at a
fluid pressure calculated using the lesser of the casing shoe
pressure and the formation fracture pressure.
2. The method of claim 1, further comprising the step of: drilling
the wellbore without using a formation pore pressure to calculate a
desired wellbore pressure.
3. The method of claim 1, wherein the step of determining a casing
shoe pressure comprises the step of: conducting a pressure test of
the formation below the casing shoe.
4. The method of claim 1, further comprising the step of: managing
the fluid at a desired pressure while drilling; circulating the
fluid in a closed system; and selecting the fluid so that the fluid
has the ability to clean the wellbore and is light enough to avoid
loss circulation but whose equivalent mud weight may be made heavy
enough to resist influx from the formation into the wellbore.
5. The method of claim 1, wherein the rotating control device is
adapted for use with a tubular, the rotating control device
comprising: an outer member; an inner member having a first sealing
element and a second sealing element; said inner member, said first
sealing element and said second sealing element rotatable relative
to said outer member; a first cavity defined by said inner member,
the tubular, said first sealing element and said second sealing
element; and the method further comprising the step of:
communicating a pressurized fluid to said first cavity to provide a
predetermined fluid pressure to said first cavity to reduce the
differential pressure between said wellbore fluid pressure and said
predetermined first cavity fluid pressure on said first sealing
element.
6. The method of claim 5, wherein the rotating control device
further comprising: a third sealing element rotatable relative to
said outer member; a second cavity defined by the tubular, said
third sealing element and one of said first and second sealing
elements; and further comprising the step of: communicating a
pressured fluid to said second cavity to provide a predetermined
fluid pressure to said second cavity to reduce the pressure
differential pressure between said predetermined first cavity fluid
pressure and said predetermined second cavity fluid pressure on
said one of said first and second sealing elements.
7. The method of claim 6, wherein the predetermined fluid pressure
in said first cavity is greater than the predetermined fluid
pressure in said second cavity, and said predetermined fluid
pressure in said first cavity is greater than said wellbore fluid
pressure.
8. The method of claim 6, wherein the predetermined fluid pressure
in said first cavity is less than the predetermined fluid pressure
in said second cavity and said predetermined fluid pressure in said
first and second cavity is less than said wellbore fluid
pressure.
9. The method of claim 6, wherein said wellbore fluid pressure is
greater than the predetermined fluid pressure in said first cavity
and the predetermined fluid pressure in said first cavity is
greater than the predetermined fluid pressure in said second
cavity.
10. The method of claim 1, wherein said rotating control device
having a pressure rating greater than said casing shoe pressure or
said formation fracture pressure.
11. The method of claim 1, further comprising the steps of:
positioning a blowout preventer stack between the wellbore and said
rotating control device and said blowout preventer stack having a
pressure rating; and positioning said rotating control device
having a pressure rating substantially equal to said blowout
preventer stack pressure rating.
12. Method for providing a differential pressure on a first sealing
element of a rotating control device having an inner member having
the first sealing element and a second sealing element rotatable
relative to an outer member, comprising the steps of: determining a
wellbore pressure at a wellhead; calculating a predetermined fluid
cavity pressure using the determined wellbore pressure; sealing
said first sealing element and said second sealing element of the
rotating control device with a tubular; and supplying the
predetermined fluid cavity pressure in a first cavity defined by
the rotating control device inner member, the rotating control
device first sealing element and the rotating control device second
sealing element when said first sealing element and said second
sealing element are sealed on the tubular.
13. The method of claim 12, further comprising the step of:
supplying a predetermined fluid pressure in a second cavity defined
by the rotating control device inner member, the rotating control
device second sealing element and the rotating control device third
sealing element when said second sealing element and said third
sealing element are sealed on the tubular.
14. The method of claim 12, wherein the fluid pressure in said
first cavity is greater than said wellbore pressure.
15. The method of claim 12, wherein the fluid pressure in said
first cavity is less than said wellbore pressure.
16. The method of claim 12, wherein the step of calculating is
enabled by a programmable logic controller.
17. The method of claim 12, further comprising the step of:
accumulating fluid pressure for use in the step of supplying a
predetermined fluid cavity pressure in a first cavity.
18. The method of claim 13, further comprising the step of:
accumulating fluid pressure for use in the step of supplying a
predetermined fluid pressure in a second cavity.
19. The method of claim 12, further comprising the step of:
circulating a fluid in said first cavity.
20. The method of claim 14, further comprising the step of:
allowing one of the sealing elements to pass a cavity fluid.
21. The method of claim 20, wherein the passed fluid includes
nitrogen from said first cavity.
22. The method of claim 12, wherein said first sealing element is
an active seal and the method further comprising the step of:
stripping out the tubular through said first sealing element after
the step of supplying the predetermined fluid pressure in said
first cavity; and reducing the sealing pressure of said active seal
during the step of stripping out the tubular.
23. The method of claim 12, wherein the fluid is a gas and the
method further comprising the step of: injecting said gas into said
first cavity through a gas expansion nozzle.
24. A rotating control apparatus, comprising: an outer member; an
inner member having a first sealing element and a second sealing
element; said inner member, said first sealing element and said
second sealing element rotatable relative to said outer member; a
first cavity defined by said inner member, said first sealing
element and said second sealing element; and said inner member
having a port to said first cavity.
25. Apparatus of claim 24, further comprising: said outer member
having a first influent port to said first cavity; and a first
effluent port from said first cavity.
26. A rotating control system adapted for use with a tubular,
comprising: a first rotating control device having: an outer
member; an inner member having a first sealing element and a second
sealing element; said inner member, said first sealing element and
said second sealing element rotatable relative to said outer
member; and a first rotating control device cavity defined by said
inner member, the tubular, said first sealing element and said
second sealing element; a first fluid source communicating with
said first rotating control device cavity to provide a
predetermined fluid pressure to said first rotating control device
cavity; a second rotating control device having: an outer member;
an inner member having a first sealing element and a second sealing
element; said inner member, said first sealing element and said
second sealing element rotatable relative to said outer member; and
a second rotating control device cavity defined by said inner
member, the tubular, said first sealing element and said second
sealing element; and a second fluid source communicating with said
second rotating control device cavity to provide a predetermined
fluid pressure to said second rotating control device cavity.
27. Apparatus of claim 26, wherein said first fluid source is the
same as said second fluid source.
28. Apparatus of claim 26, further comprising: `means for
accumulating fluid pressure to apply to said first rotating control
device cavity.
29. Apparatus of claim 28, further comprising: means for
accumulating fluid pressure to apply to said second rotating
control device cavity.
30. Apparatus of claim 26, wherein the predetermined fluid pressure
in said first rotating control device cavity is different than the
predetermined fluid pressure in said second rotating control device
cavity.
31. A rotating control apparatus adapted for use with a tubular,
comprising: an outer member; an inner member having a first sealing
element and a second sealing element; said inner member, said first
sealing element and said second sealing element rotatable relative
to said outer member; a first cavity defined by said inner member,
the tubular, said first sealing element and said second sealing
element; and a fluid source communicating with said first cavity to
provide a predetermined fluid pressure to said first cavity.
32. Apparatus of claim 31, further comprising: a third sealing
element rotatable relative to said outer member; a second cavity
defined by the tubular, said third sealing element and one of said
first and second sealing elements; and a second fluid source
communicating with said second cavity to provide a predetermined
fluid pressure to said second cavity.
33. Apparatus of claim 31, further comprising: said outer member
having a first influent port to communicate the predetermined fluid
pressure to said first cavity; and a first effluent port to
circulate said fluid from said first cavity.
34. Apparatus of claim 32, further comprising: said outer member
having a second influent port to communicate the predetermined
fluid pressure to said second cavity; and a second effluent port to
circulate said fluid from said second cavity.
35. A rotating control system adapted for use with a tubular,
comprising: a housing for positioning with a borehole; an outer
member sized to be received with said housing; an inner member
having a first sealing element and a second sealing element; said
inner member, said first sealing element and said second sealing
element rotatable relative to said outer member; a first cavity
defined by said inner member, the tubular, said first sealing
element and said second sealing element; a fluid in said borehole
having a wellbore fluid pressure; a first fluid source
communicating with said first cavity to provide a predetermined
fluid pressure based on said wellbore fluid pressure to said first
cavity.
36. System of claim 35, further comprising: a third sealing element
rotatable relative to said outer member; a second cavity defined by
the tubular, said third sealing element and one of said first and
second sealing elements; and a second fluid source communicating
with said second cavity to provide a predetermined fluid pressure
to said second cavity.
37. System of claim 35, wherein the predetermined fluid pressure is
calculated by a programmable logic controller using said wellbore
fluid pressure.
38. System of claim 36, wherein the predetermined fluid pressure in
said first cavity is different than the predetermined fluid
pressure in said second cavity, and said predetermined fluid
pressure in said first and second cavities is different than said
wellbore fluid pressure.
39. System of claim 36, wherein the predetermined fluid pressure in
said first cavity is different than the predetermined fluid
pressure in said second cavity, and said predetermined fluid
pressure in said first cavity is greater than said wellbore fluid
pressure.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] N/A
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] N/A
REFERENCE TO MICROFICHE APPENDIX
[0003] N/A
BACKGROUND OF THE INVENTION
[0004] 1. Field of the Invention
[0005] The present invention relates to rotating control devices
used when drilling wells and methods for use of these rotating
control devices.
[0006] 2. Description of the Related Art
[0007] Rotating control devices (RCDs) have been used for many
years in the drilling industry for drilling wells. An internal
sealing element fixed with an internal member of the RCD seals
around the outside diameter of a tubular and rotates with the
tubular. The tubular may be slidingly run through the RCD as the
tubular rotates or when the tubular, such as a drill string, casing
or coil tubing is not rotating. Examples of some proposed RCDs are
shown in U.S. Pat. Nos. 5,213,158; 5,647,444 and 5,662,181. The
internal sealing element may be passive or active. Passive sealing
elements, such as stripper rubber sealing elements, can be
fabricated with a desired stretch-fit. The wellbore pressure in the
annulus acts on the cone shaped stripper rubber sealing elements
with vector forces that augment a closing force of the stripper
rubber sealing elements around the tubular. An example of a
proposed stripper rubber sealing element is shown in U.S. Pat. No.
5,901,964. RCDs have been proposed with a single stripper rubber
sealing element, as in U.S. Pat. Nos. 4,500,094 and 6,547,002; and
Pub. No. US 2007/0163784, and with dual stripper rubber sealing
elements, as in the '158 patent, '444 patent and the '181 patent,
and U.S. Pat. No. 7,448,454. U.S. Pat. No. 6,230,824 proposes two
opposed stripper rubber sealing elements, the lower sealing element
positioned in an axially downward, and the upper sealing element
positioned in an axially upward (see FIGS. 4B and 4C of '824
patent).
[0008] Unlike a stripper rubber sealing element, an active sealing
element typically requires a remote-to-the-tool source of hydraulic
or other energy to open or close the sealing element around the
outside diameter of the tubular. An active sealing element can be
deactivated to reduce or eliminate the sealing forces of the
sealing element with the tubular. RCDs have been proposed with a
single active sealing element, as in the '784 publication, and with
a stripper rubber sealing element in combination with an active
sealing element, as in U.S. Pat. Nos. 6,016,880 and 7,258,171 (both
with a lower stripper rubber sealing element and an upper active
sealing element), and Pub. No. US 2005/0241833 (with lower active
sealing element and upper stripper rubber sealing element).
[0009] A tubular typically comprises sections with varying outer
surface diameters. RCD passive and active sealing elements must
seal around all of the rough and irregular surfaces of the
components of the tubular, such as hardening surfaces (such as
proposed in U.S. Pat. No. 6,375,895), drill pipe, tool joints, and
drill collars. The continuous movement of the tubular through the
sealing element while the sealing element is under pressure causes
wear of the interior sealing surface of the sealing element. When
drilling with a dual annular sealing element RCD, the lower of the
two sealing elements is typically exposed to the majority of the
pressurized fluid and cuttings returning from the wellbore, which
communicate with the lower surface of the lower sealing element
body. The upper sealing element is exposed to the fluid that is not
blocked by the lower sealing element. When the lower sealing
element blocks all of the pressurized fluid, the lower sealing
element is exposed to a significant pressure differential across
its body since its upper surface is essentially at atmospheric
pressure when used on land or atop a riser. The highest demand on
the RCD sealing elements occurs when tripping the tubular out of
the wellbore under high pressure.
[0010] American Petroleum Institute Specification 16RCD (API-16RCD)
entitled "Specification for Drill Through Equipment--Rotating
Control Devices," First Edition, .COPYRGT. February 2005 American
Petroleum Institute, proposes standards for safe and functionally
interchangeable RCDs. The requirements for API-16RCD must be
complied with when moving the drill string through a RCD in a
pressurized wellbore. The sealing element is inherently limited in
the number of times it can be fatigued with tool joints that pass
under high differential pressure conditions. Of course, the deeper
the wellbores are drilled, the more tool joints that will be
stripped through sealing elements, some under high pressure.
[0011] In more recent years, RCDs have been used to contain annular
fluids under pressure, and thereby manage the pressure within the
wellbore relative to the pressure in the surrounding earth
formation. During such use, the sealing element in the RCD can be
exposed to extreme wellbore fluid pressure variations and
conditions. In some circumstances, it may be desirable to drill in
an underbalanced condition, which facilitates production of
formation fluid to the surface of the wellbore since the formation
pressure is higher than the wellbore pressure. U.S. Pat. No.
7,448,454 proposes underbalanced drilling with an RCD. At other
times, it may be desirable to drill in an overbalanced condition,
which helps to control the well and prevent blowouts since the
wellbore pressure is greater than the formation pressure. While
Pub. No. US 2006/0157282 generally proposes Managed Pressure
Drilling (MPD), International Pub. No. WO 2007/092956 proposes
Managed Pressure Drilling (MPD) with an RCD. Managed Pressure
Drilling (MPD) is an adaptive drilling process used to control the
annulus pressure profile throughout the wellbore. The objectives
are to ascertain the downhole pressure environment limits and to
manage the hydraulic annulus pressure profile accordingly.
[0012] One equation used in the drilling industry to determine the
equivalent weight of the mud and cuttings in the wellbore when
circulating with the rig mud pumps on is:
Equivalent Mud Weight (EMW)=Mud Weight Hydrostatic
Head+.DELTA.Circulating Annulus Friction Pressure (AFP)
This equation would be changed to conform the units of measurements
as needed. In one variation of MPD, the above Circulating Annulus
Friction Pressure (AFP), with the rig mud pumps on, is swapped for
an increase of surface backpressure, with the rig mud pumps off,
resulting in a Constant Bottomhole Pressure (CBHP) variation of
MPD, or a constant EMW, whether the mud pumps are circulating or
not. Another variation of MPD is proposed in U.S. Pat. No.
7,237,623 for a method where a predetermined column height of heavy
viscous mud (most often called kill fluid) is pumped into the
annulus. This mud cap controls drilling fluid and cuttings from
returning to surface. This pressurized mud cap drilling method is
sometimes referred to as bull heading or drilling blind.
[0013] The CBHP MPD variation is achieved using non-return valves
(e.g., check valves) on the influent or front end of the drill
string, an RCD and a pressure regulator, such as a drilling choke
valve, on the effluent or back return side of the system. One such
drilling choke valve is proposed in U.S. Pat. No. 4,355,784. A
commercial hydraulically operated choke valve is sold by M-I Swaco
of Houston, Tex. under the name SUPER AUTOCHOKE. Also, Secure
Drilling International, L.P. of Houston, Tex., now owned by
Weatherford International, Inc., has developed an electronic
operated automatic choke valve that could be used with its
underbalanced drilling system proposed in U.S. Pat. Nos. 7,044,237;
7,278,496 and 7,367,411 and Pub. No. US2008/0041149 A1. In summary,
in the past, an operator of a well has used a manual choke valve, a
semi-automatic choke valve and/or a fully automatic choke valve for
an MPD program.
[0014] Generally, the CBHP MPD variation is accomplished with the
choke valve open when circulating and the choke valve closed when
not circulating. In CBHP MPD, sometimes there is a 10 choke-closing
pressure setting when shutting down the rig mud pumps, and a 10
choke-opening setting when starting them up. The mud weight may be
changed occasionally as the well is drilled deeper when circulating
with the choke valve open so the well does not flow. Surface
backpressure, within the available pressure containment capability
rating of an RCD as discussed below, is used when the pumps are
turned off (resulting in no AFP) during the making of pipe
connections to keep the well from flowing. Also, in a typical CBHP
application, the mud weight is reduced by about 0.5 ppg from
conventional drilling mud weight for the similar environment.
Applying the above EMW equation, the operator navigates generally
within a shifting drilling window, defined by the pore pressure and
fracture pressure of the formation, by swapping surface
backpressure, for when the pumps are off and the AFP is eliminated,
to achieve CBHP.
[0015] As discussed above, the CBHP MPD variation can only apply
surface backpressure within the available pressure containment
rating of an RCD. Pressure test results before the Feb. 6, 1997
filing date of the '964 patent for the Williams Model 7100 RCD
disclose stripper rubber sealing element failures at working
pressures above 2500 psi (17,237 kPa) when the drill string is
rotating. The Williams Model 7100 RCD with 7 inch (17.8 cm) ID is
designed for a static pressure of 5000 psi (34,474 kPa) when the
drill pipe is not rotating. The Williams Model 7100 RCD is
available from Weatherford International of Houston, Tex.
Weatherford International also manufactures a Model 7800 RCD and a
Model 7900 RCD. FIG. 6 is a pressure rating graph for the
Weatherford Model 7800 RCD that shows wellbore pressure in pounds
per square inch (psi) on the vertical axis, and RCD rotational
speed in revolutions per minute (RPM) on the horizontal axis. The
maximum allowable wellbore pressure without exceeding operational
limits for the Weatherford Model 7800 RCD is 2500 psi (17,237 kPa)
for rotational speeds of 100 RPM or less. The maximum allowable
pressure decreases for higher rotational speeds. Like the Williams
Model 7100 RCD, the Weatherford Model 7800 RCD has a maximum
allowable static pressure of 5000 psi (34,474 kPa). The Williams
Model 7100 RCD and the Weatherford Model 7800 and Model 7900 RCDs
all have passive sealing elements. Weatherford also manufactures a
lower pressure Model 7875 self-lubricated RCD bearing assembly with
top and bottom flanges and a lower pressure Model 7875
self-lubricated bell nipple insert RCD bearing assembly with a
bottom flange only. Since neither Model 7875 has means of
circulating coolant to remove frictional heat, their pressure vs.
RPM ratings are lower than the Model 7800 and the Model 7900.
Weatherford also manufactures an active sealing element RCD, RBOP
5K RCD with 7 inch ID, which has a maximum allowable stripping
pressure of 2500 psi, maximum rotating pressure of 3500 psi (24,132
kPa), and maximum static pressure of 5000 psi.
[0016] Pressure differential systems have been proposed for use
with RCD components in the past. For example, U.S. Pat. No.
5,348,107 proposes a pressurized lubricant system to lubricate
certain seals that are exposed to wellbore fluid pressures.
However, unlike the RCD tubular sealing elements discussed above,
the seals that are lubricated in the '107 patent do not seal with
the tubular. Pub. No. US 2006/0144622 also proposes a system to
regulate the pressure between two radial seals. Again, the seals
subject to this pressure regulation do not seal with the drill
string. The '622 publication also proposes an active sealing
element in which fluid is supplied to energize a flexible bladder,
and the pressure within the bladder is maintained at a controlled
level above the wellbore pressure. The '833 publication proposes an
active sealing element in which a hydraulic control maintains the
fluid pressure that urges the sealing element toward the drill
string at a predetermined pressure above the wellbore pressure.
U.S. Pat. No. 7,258,171 proposes a system to pressurize lubricants
to lubricate bearings at a predetermined pressure in relation to
the surrounding subsea water pressure. Also, U.S. Pat. No.
4,312,404 proposes a system for leak protection of a rotating
blowout preventer and U.S. Pat. No. 4,531,591 proposes a system for
lubrication of an RCD.
[0017] The above discussed U.S. Pat. Nos. 4,312,404; 4,355,784;
4,500,094; 4,531,591; 5,213,158; 5,348,107; 5,647,444; 5,662,181;
5,901,964; 6,016,880; 6,230,824; 6,375,895; 6,547,002; 7,040,394;
7,044,237; 7,237,623; 7,258,171; 7,278,496; 7,367,411; 7,448,454;
and 7,487,837; and Pub. Nos. US 2005/0241833; 2006/0144622;
2006/0157282; and 2007/0163784; 2008/0041149; and International
Pub. No. WO 2007/092956 or PCT/US2007/061929 are hereby
incorporated by reference for all purposes in their entirety. U.S.
Pat. Nos. 5,647,444; 5,662,181; 5,901,964; 6,547,002; 7,040,394;
7,237,623; 7,258,171; 7,448,454 and 7,487,837; and Pub. Nos. US
2005/0241833; 2006/0144622; 2006/0157282; and 2007/0163784; and
International Pub. No. WO 2007/092956 or PCT/US2007/061929 are
assigned to the assignee of the present invention.
[0018] A need exists for an RCD that can safely operate in dynamic
or working conditions in annular wellbore fluid pressures greater
than 2500 psi (17,237 kPa). Customers of the drilling industry have
expressed a desire for a higher safety factor in both the static
and dynamic rating of available RCDs for certain applications. A
higher safety factor or dynamic rating would allow for use of RCDs
to manage pressurized systems in well prospects with high wellbore
pressure, such as in deep offshore wells. It would also be
desirable if the design of the RCD complied with API-16RCD
requirements. Furthermore, use of the higher rated RCD with a
higher surface backpressure with a fluid program that disregards
pore pressure and instead uses the fracture pressure of the
formation and casing shoe leak off or pressure test as limiting
pressure factors would be desirable. This novel drilling limitation
variation of MPD would be desirable in that it would allow use of
readily available, lighter mud weight and less expensive drilling
fluids while drilling deeper with a larger resulting tubular
opening area.
BRIEF SUMMARY OF THE INVENTION
[0019] A method and system are provided a high pressure rated RCD
by, among other features, limiting the fluid pressure differential
to which a RCD sealing element is exposed. For a dual annular
sealing element RCD, a pressurized cavity fluid is communicated to
the RCD cavity located between the two sealing elements. Sensors
can be positioned to detect the wellbore annulus fluid pressure and
temperature and the cavity fluid pressure and temperature in the
RCD cavity and at other desired locations. The pressures and
temperatures may be compared, and the cavity fluid pressure and
temperature applied in the RCD cavity may be adjusted. The pressure
differential to which one or more of the sealing elements is
exposed may be reduced. The cavity fluid may be water, drilling
fluid, gas, lubricant from the bearings, coolant from the cooling
system, or hydraulic fluid used to activate an active sealing
element. The cavity fluid may be circulated, which may be
beneficial for lubricating and cooling or may be bullheaded. In
another embodiment, the RCD may have more than two sealing
elements. Pressurized cavity fluids may be communicated to each of
the RCD internal cavities located between the sealing elements.
Sensors can be positioned to detect the wellbore annulus fluid
pressure and temperature and the cavity fluid pressures and
temperatures in the RCD cavities. Again, the pressures and
temperatures may be compared, and the cavity fluid pressures and
temperatures in all of the RCD internal cavities may be
adjusted.
[0020] In still another embodiment, conventional RCDs and rotating
blowout preventers RBOPs can be stacked and adapted to communicate
cavity fluid to their respective cavities to share the differential
pressure across the sealing elements.
[0021] With a higher pressure rated RCD, a Drill-To-The-Limit
(DTTL) drilling method variant to MPD would be feasible where
surface backpressure is applied whether the mud is circulating
(choke valve open) or not (choke valve closed). Because of the
constant application of surface backpressure, the DTTL method can
use lighter mud weight that still has the cutting carrying ability
to keep the borehole clean. With a higher pressure rated RCD, the
DTTL method would identify the weakest component of the pressure
containment system, usually the fracture pressure of the formation
or the casing shoe Leak Off Test (LOT) or pressure test. In the
DTTL method, since surface backpressure is constantly applied, the
pore pressure limitation of the conventional drilling window, such
as used in the CBHP method and other MPD methods, can be
disregarded in developing the fluid and drilling programs.
[0022] With a higher pressure rated RCD, such as 5,000 psi dynamic
or working pressure and 10,000 psi static pressure, the limitation
will usually be the fracture pressure of the formation or the LOT.
Using the DTTL method, a deeper wellbore can be drilled with a
larger resulting end tubulars opening area, such as casings or
production liners, than would be possible with any other MPD
application, including, but not limited to, the CBHP method.
BRIEF DESCRIPTION OF THE DRAWINGS
[0023] A better understanding of the present invention can be
obtained with the following detailed descriptions of the various
disclosed embodiments in the drawings:
[0024] FIG. 1 is a multiple broken elevational view of an exemplary
embodiment of a land drilling rig showing an RCD positioned above a
blowout preventer ("BOP") stack, a cemented casing and casing shoe
in partial cut away section, and a drill string extending through a
formation into a wellbore.
[0025] FIG. 2 is a multiple broken elevational view of an exemplary
embodiment of a floating semi-submersible drilling rig showing a
RCD positioned above a BOP stack, a marine riser extending upward
from an annular BOP on the surface, a cemented casing and casing
shoe in partial cut away section, and a drill string extending
through a formation into the wellbore.
[0026] FIG. 3 is a comparison chart of fluid programs and casing
programs for the prior art conventional and Constant Bottom Hole
Pressure "CBHP" MPD methods versus the DTTL method while drilling
through a number of geological anomalies such as the Touscelousa
(near Baton Rouge, La.) sand problems.
[0027] FIG. 4 is a comparison chart comparing the fluid programs
and casing programs for prior art conventional and CBHP MPD methods
versus the DTTL method for a jack-up rig in 400' of water.
[0028] FIG. 4A is a comparison chart of a light mud pressure
gradient to a heavy mud pressure gradient relative to a pore
pressure/fracture pressure window.
[0029] FIG. 5A is a comparison chart of a prior art deep water well
design for conventional versus Drilling with Casing (DwC).
[0030] FIG. 5B is a comparison chart of casing programs comparing
the prior art conventional program to the DTTL method program that
provides two contingency casing strings.
[0031] FIG. 5C is a comparison chart of casing programs using the
prior art conventional fluid program to 16,000' then using the DTTL
method to provide a contingency casing string.
[0032] FIG. 6 is a prior art wellbore pressure rating vs. RPM graph
for an exemplary prior art Weatherford Model 7800 RCD.
[0033] FIG. 7 is a cut away section elevational view of an RCD with
two passive sealing elements, sensors for measuring pressures and
temperatures in the diverter housing and the RCD internal cavity,
and influent and effluent lines for circulating cavity fluid into,
in and out of the RCD internal cavity. Also, arrows illustrate
pressurized flow of fluids to cool the bottom passive sealing
element.
[0034] FIG. 8 is a cut away section elevational view of an RCD with
a lower active sealing element (shown inflated on one side and
deflated on the other side to allow the tool joint to pass) and an
upper passive sealing element, sensors for measuring pressures and
temperatures in the diverter housing and the RCD internal cavity,
and influent and effluent lines for circulating cavity fluid into,
in and out of the RCD internal cavity.
[0035] FIG. 9 is a cut away section elevational view of an RCD with
a lower active sealing element and two upper passive sealing
elements, sensors for measuring pressures and temperatures from the
diverter housing and into, in and out of the RCD upper and lower
internal cavities, and influent and effluent lines for
communicating cavity fluid into, in and out of each RCD internal
cavity.
[0036] FIG. 10 is a cut away section elevational view of an RCD
with two passive sealing elements, sensors for measuring pressures
and temperatures in the diverter housing and into the RCD internal
cavity, a pressure regulator, and influent and effluent lines for
circulating cavity fluid into, in and out of the RCD internal
cavity. Also, arrows illustrate pressurized flow of fluids to cool
the bottom passive sealing element.
[0037] FIG. 11 is a cut away section elevational view of an RCD
with three passive sealing elements positioned with a unitary
housing, sensors for measuring pressures and temperatures in the
diverter housing and into and out of the RCD upper and lower
internal cavities, upper and lower RCD internal cavity pressure
regulators, a mud line to communicate mud to the cavities via their
respective regulators and influent and effluent lines for
communicating cavity fluid into, in and out of each RCD internal
cavity.
[0038] FIG. 11A is enlarged detailed elevational cross-sectional
view of the RCD upper pressure compensation means as indicated in
FIG. 11 to maintain the lubrication pressure above the wellbore
pressure.
[0039] FIG. 11B is enlarged detailed elevational cross-sectional
view of the RCD lower pressure compensation means as indicated in
FIG. 11 to maintain the lubrication pressure above the wellbore
pressure.
[0040] FIGS. 12A and 12B is a cut away section elevational view of
an RCD with four passive sealing elements, sensors for measuring
pressures and temperatures into, in and out of the diverter housing
and into and out of the three RCD internal cavities, three RCD
internal cavity pressure regulators and influent and effluent lines
for communicating cavity fluid into, in and out of each RCD
internal cavity. A programmable logic controller "PLC" is wired to
the three pressure regulators to provide desired relative pressures
in each cavity for differential pressure and/or "burps" of the
sealing elements with, for example, a nitrogen pad.
[0041] FIGS. 13A, 13B and 13C is a cut away section elevational
view of an RCD with an active sealing element and three passive
sealing elements on a common RCD inner member above another
independent active sealing element, sensors for measuring pressures
and temperatures in the diverter housing and the RCD four internal
cavities between these five sealing elements, four RCD internal
cavity pressure regulators, ports in the RCD bearing assembly for
communicating cavity fluid with each RCD internal cavity. Some of
the housings and spools are connected by bolting and the remaining
housing and spools are connected using a clam shell clamping
device.
[0042] FIGS. 14A and 14B is a cut away section elevational view of
an RCD with two passive sealing elements above an independent
active sealing element, sensors for measuring pressures and
temperatures in the diverter housing and the RCD internal cavities,
upper and lower RCD internal cavity pressure regulators, sized
ports in the RCD bearing assembly for communicating cavity fluid
with each RCD internal cavity. The regulators are provided with an
accumulator, and a solenoid valve is located in a line running from
the diverter housing for controlling mud with cuttings to the upper
two pressure regulators. The active sealing element can be
pressurized to reduce slippage with the tubular if the PLC
indicates rotational velocity differences between the passive
sealing elements and the active sealing element.
[0043] FIGS. 15A, 15B and 15C is a cut away section elevational
view of an RCD with four passive sealing elements, sensors for
measuring pressures and temperatures in the diverter housing and
the three RCD internal cavities, three RCD internal cavity pressure
regulators and sized ports in the RCD bearing assembly for
communicating cavity fluid with each RCD internal cavity.
[0044] FIGS. 16A and 16B is a cut away section elevational view of
an RCD with one active sealing element and two passive sealing
elements, sensors for measuring pressures and temperatures in the
diverter housing and into the RCD upper and lower internal
cavities, upper and lower RCD internal cavity pressure regulators,
and influent and effluent lines for communicating cavity fluid
into, in and out of each RCD internal cavity. Three accumulators
are provided in the line connecting the upper and lower pressure
regulators. The active sealing element pressure can be controlled
by the PLC relative to the rotation of the inner member supporting
the two passive sealing elements.
[0045] FIGS. 17A and 17B is a cut away section elevational view of
an RCD with two passive sealing elements above an independent
active sealing element, sensors for measuring pressures and
temperatures in the diverter housing and the RCD upper and lower
internal cavities, upper and lower RCD internal cavity pressure
regulators and ports in the RCD bearing assembly for communicating
cavity fluid with each RCD internal cavity. An accumulator is
provided in the lines between the pressure regulators and a
solenoid valve is provided in the line from the diverter housing.
Additionally, the tubular extending through the RCD is provided
with a stabilizer below the RCD.
DETAILED DESCRIPTION OF THE INVENTION
[0046] The DTTL method and the pressure sharing RCD systems may be
used in many different drilling environments, including those
environments shown in FIGS. 1 and 2. Exemplary drilling rigs or
structures for use with the invention, generally indicated as S,
are shown in FIGS. 1 and 2. Although a land drilling rig S is shown
in FIG. 1, and an offshore floating semi-submersible rig S is shown
in FIG. 2, other drilling rig configurations and embodiments are
contemplated for use with the invention for both offshore and land
drilling. For example, the invention is equally applicable to
drilling rigs such as jack-up, semi-submersibles, submersibles,
drill ships, barge rigs, platform rigs, and land rigs. Turning to
FIG. 1, an RCD 10 is positioned below the drilling deck or floor F
of the drilling rig S and above the BOP stack B. RCD 10 may include
any of the RCD pressure sharing systems shown in FIGS. 7 to 17B or
other adequately pressure rated RCD. The RCD, where possible,
should be sized to be received through the opening in the drilling
deck or floor F. The BOP stack B is positioned over the wellhead W.
Casing C is hung from wellhead W and is cemented into position.
Casing shoe CS at the base of casing C is also cemented into
position. Drilling string DS extends through the RCD 10, BOP stack
B, wellhead W, casing C, wellbore WB and casing shoe CS into the
wellbore borehole BH. As used herein, a wellbore WB may have casing
in it or may be open (i.e., uncased as wellbore borehole BH); or a
portion of it may be cased and a portion of it may be open. Mud
pump P is on the surface and is in fluid communication with mud pit
MP and drill string DS.
[0047] In FIG. 2, casing C is hung from wellhead W, which is
positioned on the ocean floor. Casing C is cemented in place along
with casing shoe CS. Marine riser R extends upward from the top of
the wellhead W. Drill string DS is positioned through the RCD 10,
BOP stack B, riser R, wellhead W, casing C and wellbore WB into the
wellbore borehole BH. BOP stack B is on top of riser R, and RCD 10
is positioned over BOP stack B and below rig floor F. Mud pump P is
on the drilling rig and is in fluid communication with mud tank MT
and drill string DS.
[0048] DTTL Method
[0049] In the DTTL method, a pressure containment system may be
configured with casing C, a pressure rated RCD, such as a pressure
sharing RCD system; for example, as shown in FIGS. 7 to 17B, drill
string non-return or check valves, a drilling choke manifold with a
manual or adjustable automatic choke valve, and a mud-gas separator
or buster. As will be discussed below in detail, in the DTTL
method, the weakest component of the well construction program is
determined. This will usually be the fracture gradient of the
formation, the casing shoe integrity, or the integrity of any other
component of the closed pressurized circulating fluid system's
pressure containment capability. A leak off test ("LOT"), as is
known in the art, may be run on the casing shoe CS to determine its
integrity. The LOT involves a pressure test of the formation
directly below the casing shoe CS to determine a casing shoe
fracture pressure. The LOT is generally conducted when drilling
resumes after an intermediate casing string has been set. The LOT
provides the maximum pressure that may be safely applied and is
typically used to design the mud program or choke pressures for
well control purposes. Although there may be more than one casing
shoe in the well, the most likely candidate to be the weakest link
relative to the integrity of all the other casing shoes in the
casing program will typically be the casing shoe CS that is
immediately above the open borehole BH being drilled. A formation
integrity test ("FIT"), as is also known in the art, may be run on
the formation. The fracture gradient for the formation may be
calculated from the FIT results. Surface equipment that may limit
the amount of pressure that may be applied with the DTTL method
include the RCD, the choke manifold, the mud-gas separator, the
flare stack flow rate, and the mud pumps. The casing itself may
also be the weakest component. Some of the other candidates for the
limiting component include the standpipe assembly, non-return
valves (NRVs), and ballooning. It is also contemplated that
engineering calculations and/or actual experience on similar wells
and/or offset well data from, for example, development wells could
be used to determine the "limit" when designing the DTTL method
fluid program. With the DTTL method, hydraulic flow modeling may be
used to determine surface back pressures to be used, and to aid in
designing the fluids program and the casing seat depths. Hydraulic
flow modeling may also determine if the drilling rig's existing
mud-gas separator has the appropriate capacity.
[0050] The "ballooning", discussed above, is a phenomenon which
occurs within the uncased hole as a direct result of pressures in
the wellbore that cause an increase in the volume of fluids within,
but do not fracture the wellbore to cause mud loss. Most
geologically young sediments are somewhat elastic (e.g., not hard
rock). Companion to ballooning is "breathing". Both contribute to
wellbore instability by massaging the walls of the wellbore.
Breathing raises questions for a driller when making jointed pipe
connections; mud pumps are off, but the rig's mud pits continue to
show flow from the wellbore. Specifically, the driller questions
whether the well is taking a kick of formation fluids requiring mud
weight to be added . . . or whether the well is giving back some of
the volumes of fluid that expanded the wellbore with the last stand
of pipe drilled (by Circulating Annulus Friction Pressure (AFP)
being added to the hydrostatic weight of the mud). The FIT can
detect ballooning as well as establish an estimate of the fracture
pressure, similar to testing the "yield point" vs. "break point" of
metals and "elongation" vs. "tensile strength" of an elastomeric.
Whether real or perceived, ballooning may also be seen as the
"limit" to the DTTL method when determining the mud to drill with
and casing shoe depths.
[0051] Using the DTTL method, the wellbore WB may be drilled at a
fluid pressure slightly lower than the weakest component. Less
complex wells may not require hydraulic flow modeling, the LOT, or
the FIT, if there is confidence that the wellbore WB may be drilled
by just tooling up at the surface to deal with the uncertainties of
the formation pressures. This may apply to the drilling of
reservoirs that are progressively more depleted. It is also
contemplated that the DTTL method may use a prior art RCD for
certain low pressure formations rather than the pressure sharing
RCD systems shown in FIGS. 7 to 17B. However, if an available RCD
is used, it may be the weakest component, particularly if a factor
of safety is applied. The Minerals Management Service (MMS)
requires a 200% safety factor for offshore wells. In effect, this
requires that the RCD be used at half its published pressure
rating. One of the objectives of the high pressure rated RCD is to
eliminate the RCD as the weakest component of the DTTL method.
[0052] Complimentary technologies that may be used with the DTTL
method include downhole deployment valves, equivalent circulation
density (ECD) reduction tools, continuous flow subs and continuous
circulating systems, surface mud logging, micro-flux control,
dynamic density control, dual gradient MPD, and gasified liquids.
Surface mud logging allows for cuttings analysis for determining,
among other things, rock strength and wellbore stability with lag
time. Micro-flux control may allow early kick detection, real time
wellbore pressure profile, and automated choke controls. As
discussed above, Secure Drilling International, LP provides a
micro-flux control system. Dynamic density control adds
geomechanics capabilities to the real time analysis and prediction
of stresses on the rock being drilled. Dynamic density control may
be useful in determining the optimum DTTL method drilling fluid
weight and casing set points in some complex wells. Gasified fluids
may be used to keep the EMW of the drilling fluid low enough to
avoid rupturing a casing seat, or exceeding the predetermined
pressure of fracture gradient or FIT.
[0053] Turning to FIG. 3, the advantages of the DTTL method are
shown for a particular geologic formation. The formation pore
pressure and fracture gradient are shown for an onshore geologic
prospect. The prospect has a shifting drilling window, which is the
area between the fracture gradient and the pore pressure. If the
total EMW is less than the pore pressure, the well will flow. If
the total EMW is greater than the facture gradient, then there may
be an underground blowout and loss of circulation. The formation
has kick-loss hazard zones around 1300 meters (4265 feet) and 1700
meters (5577 feet) in the reservoir. These kick-loss hazards may
manifest themselves as differential sticking, loss circulation,
influx, twist-offs, well control issues, and non-productive time.
With conventional drilling methods, including the CBHP MPD method,
concerns with kick-loss hazards often cause casing program
designers to specify fail safe casing string programs.
[0054] The left side of the chart of FIG. 3 shows a comparison of
exemplary drilling fluids programs for the CBHP MPD method and the
DTTL method. The Equivalent Mud Weight ("EMW") for the drilling
fluid used with the CBHP MPD method is shown with a dashed line
from the surface until a depth of about 2000 meters (6561 feet).
Typically, the EMW is a measure of the pressure applied to the
formation by the circulating drilling fluid at a depth. When
referring to the CBHP and DTTL methods, the fluid systems are
referred to as an equivalent from the conventional hydrostatic mud
weight. The EMW for the drilling fluid is about 9 ppg for the CBHP
MPD method. Hydrostatic mud weight is sometimes expressed in ppg.
Dynamic or circulating mud weight (EMW) is expressed in ppge, where
the "e" is for "equivalent." The EMW for the drilling fluid used
with the DTTL method is shown with a solid line from the surface
until a depth around 2000 meters (6561 feet). The EMW for the
drilling fluid of the DTTL method is slightly less than 7 ppg. With
the CBHP MPD method, the EMW of the drilling fluid is kept
substantially constant to about 1900 meters (6233 feet), and within
the drilling window except around 1700 meters (5577 feet), where it
exceeds the fracture gradient. As shown in FIG. 3, with the DTTL
method, the EMW of the drilling fluid may be a lower value than
that for the drilling fluid with the CBHP MPD method for this
prospect. It is contemplated that that the EMW of the drilling
fluid may be two or three ppg less for the DTTL method, although
other amounts are also contemplated.
[0055] In the DTTL method some amount of surface back pressure may
be held whether or not the drilling fluid is circulating. Also, in
the DTTL method, whatever the degree of static or dynamic
underbalance of the EMW of the drilling fluid relative to the pore
pressure, there will be an equivalent amount of surface back
pressure applied to keep the total EMW in the drilling window above
the pore pressure and below the fracture gradient. The objective is
not to maintain a constant EMW, as CBHP MPD, but to keep it within
the drilling window. The static and dynamic pressure imparted by
the drilling fluid will usually become progressively less than the
formation pore pressure as the depth increases, such as shown in
FIG. 3, from the surface to a depth of about 1200 meters (3937
feet). Therefore, a progressively higher surface back pressure may
be required as the drill bit travels deeper. In FIG. 3, the
drilling fluid weight for the DTTL method is lower than the pore
pressure in many depth locations, so that surface back pressure is
needed whether circulating or not to keep the well from flowing
(i.e. prevent influx). The amount of surface back pressure required
is directly related to the hydrostatic or circulating amount of
underbalance of the drilling fluid in the open hole. Because there
may be a gross underbalance of the drilling fluid in the borehole
at any particular time, the pressure containment capability of the
RCD becomes paramount. The back pressure may be maintained with a
back pressure control or choke system, such as proposed in U.S.
Pat. Nos. 4,355,784; 7,044,237; 7,278,496; and 7,367,411; and Pub.
No. US 2008/0041149. A hydraulically operated choke valve sold by
M-I Swaco of Houston, Tex. under the name SUPER AUTOCHOKE may be
used along with any known regulator or choke valve. The choke valve
and system may have a dedicated hydraulic pump and manifold system.
A positive displacement mud pump may be used for circulating
drilling fluids. It is contemplated that there may be a system of
choke valves, choke manifold, flow meter, and hydraulic power unit
to actuate the choke valves, as well as sensors and an intelligent
control unit. It is contemplated that the system may be capable of
measuring return flow using a flow meter installed in line with the
choke valves, and to detect either a fluid gain or fluid loss very
early, allowing gain/loss volumes to be minimized.
[0056] It is contemplated that the DTTL method may use drill string
non-return valves. Non-return or check valves are designed to
prevent fluid from returning up the drill string. It is also
contemplated that the DTTL method may use downhole deployment
valves to control pressure in the wellbore, including when the
drill string is tripped out of the wellbore. Downhole deployment
valves are proposed in U.S. Pat. Nos. 6,209,663; 6,732,804;
7,086,481; 7,178,600; 7,204,315; 7,219,729; 7,255,173; 7,350,590;
7,413,018; 7,451,809; 7,475,732; and Pub. Nos. US 2008/0060846 and
2008/0245531; which are all hereby incorporated by reference for
all purposes in their entirety and are assigned to the assignee of
the present application. For the drilling fluid traveling down the
wellbore, it may be pressurized in a system of the positive
displacement mud pump, standpipe hose, the drill string, and the
drill string non-return valves. For the drilling fluid returning up
the annulus, it may be pressurized in a system of the casing shoe,
casing and surface equipment, the RCD system, such as shown in
FIGS. 7 to 17B, and the dedicated choke manifold. The DTTL method
may also be used for running tubulars without rotating, including,
but not limited to, drill string, drill pipe, casing, and coiled
tubing, into and out of the hole.
[0057] While rock mechanics, rheological and chemical compatibility
issues with the formation to be drilled are factors to be
considered, the DTTL method allows for lighter, more
hydrostatically underbalanced, more readily available, and less
expensive drilling fluids to be used. The DTTL method simplifies
the drilling process by reducing non-productive time (NPT) dealing
with drilling windows. Also, the lighter drilling fluid allows for
faster and less resistive rotation of the drill string. Circulating
Annular Friction Pressure (AFP) increases in a proportion to the
weight and viscosity of the drilling fluid. It is important to
recognize that AFP is a significant limiting factor to conventional
drilling and the objective of CBHP is to counter its effect on the
wellbore pressure profile by the application of surface back
pressure when not circulating. The DTTL method's use of much
lighter drilling fluids result in a significant reduction in
pressures imparted by the circulation rate of the drilling fluid
and offers the option to circulate at much higher rates with no ill
effects. The DTTL method's drilling fluid offers another distinct
advantage in that lighter fluids are less prone for its viscosity
to increase during periods of idleness. This "jelling" manifests
itself as a spike in the EMW upon restarting the rig's mud pumps to
regain circulation. As such pressure fluctuations are detrimental
to precise management of the uncased hole pressure environment, the
DTTL method significantly minimizes the impact of jelling. However,
one must be mindful that some formations require a minimum mud
weight to aid in supporting the walls of the uncased hole,
formations such as unconsolidated sand, rubble zones, and some
grossly depleted formations. Given these considerations, the
criteria for selection of the drilling fluids may be focused upon
(1) the ability to clean the hole (cuttings carrying ability), (2)
a light enough weight to avoid loss circulation, and (3) a heavy
enough weight so that the back pressure required to prevent an
influx from the formation will not exceed the limits of the weakest
component of the well construction program. In designing the fluids
program for the DTTL method, the formation pore pressure is not
used, with the objective being to avoid exceeding the "weakest
link" of the fracture gradient, the casing shoe integrity, or the
integrity of any other component of the closed pressurized
circulating fluid system's pressure containment capability. A LOT,
offset well information or rock mechanics calculations should
provide the maximum allowable pressure for the casing shoe. In land
drilling programs, the casing shoe fracture pressure will most
often not be the "weakest link" of the pressure containment system.
However, the casing shoe pressure integrity may be less than the
formation fracture pressure when drilling offshore, such as in
geologically young particulate sediments, through salt domes, whose
yielding characteristics challenge the ability to obtain an
acceptable casing and casing shoe cement job.
[0058] The right side of the chart in FIG. 3 shows a comparison of
casing programs for the conventional and CBHP MPD methods to the
DTTL method. Like the drilling fluids program, the casing program
using the DTTL method for this geologic formation is simplified in
comparison with the prior art casing programs. Simplification of
the casing program with the DTTL method is a direct result of two
distinguishing characteristics: 1.) a lighter mud imparting less
depth vs. pressure gradient upon the wellbore, enabling deeper open
holes than conventional or CBHP to be drilled before the fracture
pressure is approached requiring a casing shoe set point as best
shown in FIG. 4A, and 2.) to maintain the EMW further away from the
formation fracture gradient. For example, the DTTL method allows
for a 24 inch wellhead, as compared with a more expensive 30 inch
wellhead required by the conventional and CBHP MPD methods. The
DTTL method also allows the total depth objective to be obtained
with a larger and longer open hole than is possible with the prior
art methods. In the example of FIG. 3, the DTTL method allows for a
10 inch diameter production liner (gravel pack-type completion or
open hole) as compared with a 7 inch production liner for the
conventional method or a 41/2 inch production liner for the CBHP
MPD method. The 10 inch production liner in the DTTL method
advantageously extends completely through the reservoir, unlike the
prior art methods. As a result, the DTTL method only requires three
casing/liner size changes, compared with five changes with the CBHP
MPD method and seven changes with the conventional method. Both the
conventional and CBHP MPD methods require a dedicated casing set
point around 1700 meters (5577 feet) for the kick hazard, but the
DTTL method does not. In summary, the DTTL method allows use of
smaller diameter wellhead and casing initially and a larger
diameter liner to total depth (TD) with fewer tubular changes and
with less expensive, more readily available lighter fluids. The
contemplated maximum surface back pressure on the DTTL method would
be 975 psi (circulating); 1030 psi (during connection) and 2713 psi
(shut in). The LOT on the 133/8'' casing shoe must be less than
4140 psi.
[0059] Turning to FIG. 4, the advantages of the DTTL method are
shown in a different geologic formation with objectives of lightest
mud, highest rate of penetration (ROP), slimmest casing program,
deepest open hole below 95/8'' casing for maximum access to
reservoir. The formation pore pressure and fracture gradient are
shown for an offshore geologic prospect for a jack-up rig having a
mud line at 400 feet (122 meters). The prospect has a shifting
drilling window. The shallow gas hazard is mitigated because the
DTTL method teaches the application of surface backpressure whether
circulating or not, and encountering a shallow gas hazard simply
implies additional surface backpressure. There are kick-loss hazard
zones around 9000 feet (2743 meters) and 14,000 feet (4267 meters).
The left side of the chart shows a comparison of exemplary drilling
fluids programs for the conventional method to the DTTL method.
Note that the pressure-containing integrity of the 135/8'' casing
shoe at 9,500' has a LOT value less than the fracture pressure.
Therefore, this casing shoe is considered the limiting component
relative to DTTL fluids selection and determines the maximum amount
of surface backpressure that may be applied without risk of
fracturing the casing shoe. The EMW for the drilling fluid used
with the conventional method is shown with a series of dashed lines
starting at about 9 ppg at the surface and making several changes
until ending at about 17 ppg at a depth of about 16,000 feet (4877
meters). The conventional method is complicated by the need for
eight drilling fluid density changes to navigate through the
drilling window. The EMW for the drilling fluid of the DTTL method
is shown with a solid line at about 6.7 ppg starting at the
surface. The kick-loss hazards present challenges for the
conventional method, and require rapid mud weight changes to
navigate. In the DTTL method, the kick-loss hazards become a moot
point, unlike in the conventional method, which must rely on mud
weight changes. With CBHP, placing a casing shoe above the
kick-loss hazard zones is a prudent and common practice, typically
because of uncertainty of the accuracy of the estimated drilling
window in the kick-loss hazard zone, and one should keep the option
open to deviate from the pre-planned CBHP mud weight. With the DTTL
method, the EMW of the drilling fluid is kept substantially
constant to about 16,000 feet (4877 meters). Unlike the
conventional method, in the DTTL method some amount of surface back
pressure may be held on the drilling fluid. In the DTTL method
surface back pressure is provided to keep the total EMW above pore
pressure but below the fracture gradient. As should now be
understood, the DTTL method simplifies the drilling process as it
allows for less changes in the drilling fluid as compared with the
conventional method. Again, the DTTL method allows for lighter,
more hydrostatically underbalanced, more readily available, and
less expensive drilling fluids to be used. In designing the fluids
program with the DTTL method, the formation pore pressure is not
used, with the objective being to avoid exceeding the fracture
gradient, the casing shoe integrity, or the integrity of any other
component of the closed pressurized circulating fluid system's
pressure containment capability.
[0060] The right side of the chart in FIG. 4 shows a comparison of
casing programs for the conventional and CBHP MPD methods to the
DTTL method. Like the drilling fluids program, the casing program
of the DTTL method for this geologic formation is simplified in
comparison with the prior art casing programs. For example, the
DTTL method allows for a 24 inch wellhead, as compared with a more
expensive 30 inch wellhead required by the conventional and CBHP
MPD methods. The DTTL method also allows the total depth objective
to be obtained with a larger and longer open hole than is possible
with the prior art methods. The 95/8'' casing and 7 inch production
liner in the DTTL method extends completely through the Reservoir,
unlike the prior art methods. In the example of FIG. 4, the DTTL
method has three casing/liner size changes, compared with five
changes with the CBHP MPD method. The conventional, CBHP MPD and
DTTL methods require a dedicated casing set point around 14,000
feet (4267 meters). The casing shoe is set at 14,000 feet (4267
meters) for the kick-loss hazard and for enabling drilling fluid
density adjustments below that point required to handle the new
drilling window. This DTTL method illustrates a case study where a
cemented casing shoe is the limit, as determined by a LOT,
calculations or offset well data. In this case study, the DTTL
method 135/8'' casing shoe was determined to have a limit of 13.6
ppg equivalent mud weight at the beginning of the Reservoir. As
best shown in FIG. 4, a 6.7 ppg oil-based mud is used below the
133/8'' casing (LOT, calculations or offset well data of 13.6 ppge
limit) in the DTTL method and supplied through a 5 inch drill
string DS at 500 gallons per minute. At 13,500 feet the pore
pressure is 12.5 ppge. With a surface back pressure is 4,800 psi
(circulating) and 5,015 psi (static), a high pressure RCD, as
discussed below in detail, will be required.
[0061] As is known in the art, the calculated formation pore
pressure and fracture gradient are usually not exact, and margins
of error must be considered in selecting casing set points. This
uncertainty may prompt additional casing set points in the
conventional and CBHP MPD methods that are avoided in the DTTL
method. Additional casing set points create added expense and
casing shoe issues. The DTTL method uses required amounts of
surface back pressure to guard against these uncertainties in the
formation. There is a reasonable probability that the conventional
and CBHP MPD methods as applied to the formation shown in FIG. 4
would result in a drilling program that ultimately exceeds budget
(known in the art as authorization for expenditure "AFE") due to
extra casing sizes, extra casing strings, and non-productive time
dealing with the loss portion of the kick-loss hazards, such as
differential sticking of the drill string with potential twisting
and severing of the string, loss of circulation with attendant
drilling fluid cost, and well control issues. A kick in the
kick-loss hazard zone results in having to shut in and circulate
out the kick, including waiting to increase the weight of the
drilling fluid. The DTTL method advantageously allows the operation
to avoid many kick-loss hazards. The DTTL method allows for
drilling with a lighter drilling fluid and staying further away
from the loss portion of the kick-loss hazard zone. Since there is
constant surface back pressure even when there is no circulation,
the kick portion may be more easily compensated for and controlled
using the DTTL method.
[0062] For the geologic formation depicted in FIGS. 3 and 4, the
DTTL method achieves its objectives of using the lightest and less
expensive drilling fluid, the highest rate of penetration (ROP),
the slimmest casing program, and a deeper open hole for more access
to the reservoir than either conventional or CBHP. The DTTL method
allows for the formation fracture gradient to be focused on instead
of the formation pore pressure. The drilling fluid may be selected
as described above. When the EMW of the drilling fluid is less than
the formation pore pressure, surface pressure is applied to prevent
or limit influx into the wellbore when the mud pumps are on and
drilling is occurring. When the mud pumps are off, an additional
amount of surface back pressure is applied to offset the loss of
Circulating Annular Friction Pressure (AFP). The DTTL method
effectively broadens the drilling window by not using the formation
pore pressure. The DTTL method is particularly helpful where the
formation pore pressure is relatively unknown, such as in
exploratory wells and sub-salt reservoirs, as are common in the
Gulf of Mexico.
[0063] FIG. 5A is a chart of depth in feet versus pressure
equivalent in ppg for an exemplary prior art Gulf of Mexico deep
water geologic prospect with a salt layer. A floating drilling rig
may be used to drill the well. The drilling fluid weight for
conventional drilling techniques in the salt layer is shown as
greater than the salt overburden gradient and less than the salt
fracture gradient. The prior art drilling fluid program is
complicated by the need to continuously monitor and change the
weight of the drilling fluid to stay within the drilling window.
The left side of the chart shows the casing design for prior art
conventional drilling techniques. The right side of the chart shows
the casing design for prior art Drilling with Casing ("DwC"). DwC
is an enabling technology that can be a mitigant for managing
shallow hazards. An objective of the technology is to set the first
and possibly the second casing strings significantly deeper than
with conventional drilling techniques. DwC addresses shallow
geologic hazards, wellbore instability, and other issues that would
otherwise require additional casing string sizes, ultimately
limiting open hole size at total depth ("TD").
[0064] FIG. 5B shows the same geologic prospect as in FIG. 5A. The
pressure equivalent of the drilling fluid is shown as substantially
constant at 14 ppg from a depth of around 6,900 feet (2103 meters)
to about 13,000 feet (3962 meters) while DwC. The DTTL method is
used beginning with 13,000 feet (3962 meters). The pressure
equivalent of the drilling fluid of the DTTL method is shown as
substantially constant from a depth of about 13,000 feet (3962
meters) to about 30,000 feet (9144 meters). The DTTL method
simplifies the drilling fluids program by using a lighter weight
drilling fluid than the conventional technique, and by requiring
only one change of fluid weight after a depth of 30,000 feet (9144
meters), in comparison with continuous changes required by
conventional techniques. The left side of the chart again shows the
casing design for conventional drilling techniques. The right side
of the chart shows the casing design for the DTTL method. Using the
DTTL method, a 135/8 inch casing shoe may be used at total depth of
31,000 feet (9449 meters), compared with a 93/8 inch casing shoe at
TD of 28,000 feet (8534 meters) for the conventional drilling
method. The DTTL method provides for a larger hole and deeper total
depth (TD). There are also two contingency casing strings available
with the DTTL method. It is contemplated that the DTTL method could
be used with DwC having a 135/8'' casing.
[0065] FIG. 5C is the same as FIG. 5B, except that in the DTTL
method one of the contingency casing strings has been removed,
resulting in a 117/8 inch casing shoe at TD of 31,000 feet (9449
meters). As can now be understood, sub-salt, the DTTL method
advantageously achieves the largest and deepest open hole at total
depth (TD) for production liners and expandable sand screens (ESS).
The DTTL method is particularly beneficial beneath the transition
zone in the reservoir. In conventional drilling, drilling fluid
weight is typically increased to be safe in light of the margin of
error in predicting the pore pressure. The prediction of sub-salt
formation pore pressures and formation fracture pressures has been
shown on a number of deepwater wells to be in a range of error of
as much as 2 to 3 ppge. This much error in predicting the actual
drilling window plays a continuous role in the design of a
conventional casing and fluids program. The worst case scenario
must always be planned for long in advance to obtain a permit to
drill from the MMS, in procurement decisions, in logistics of
delivery considerations, in requirements for deck space for various
casing sizes, and for other contingencies. This has an adverse
affect on the cost of the well. If the well is sub salt, then
seismographic imaging may be blurred by the plastic nature of the
salt dome. Accurate prediction of the drilling window may be
difficult. This may result in estimating on the high side when
designing the fluids program, which may explain why loss
circulation and the resulting well control issues often arise in
many drilling programs when the bit penetrates through the base of
salt in the Gulf of Mexico. The MMS requires EMW to be at least 0.5
ppge above formation pore pressure, which is a relative unknown.
Sub salt prospects in the Gulf of Mexico include Atwater Valley,
Alaminos Canyon, Garden Banks, Keathley Canyon, Mississippi Banks,
and Walker Ridge.
[0066] There are other uncertainties in the open hole below the
last casing seat that complicate conventional and CBHP MPD casing
and fluids programs. These include compressibilites, solubilities,
mechanical, thermal, and fluid transport characteristics of each
formation, natural and/or operationally induced wellbore
communicating fracture systems, undisturbed states prior to
drilling sand, and time-dependent behaviors after being penetrated
by the wellbore. With the DTTL method, surface equipment pressure
rating may be advantageously used to compensate for the relative
unknown, such as the range of error. With the DTTL method, the
driller may tool up at the surface to deal with downhole
uncertainties, rather than complicating the downhole casing and
fluids programs to handle the worst case scenario of each. As
discussed above, the DTTL method also advantageously increases the
contingency for additional casing sizes, if needed. Failed drilling
programs sometimes occur because the conventional casing program
has no margin for contingency if the geo-physics or rock mechanics
(i.e. wellbore instability) are different than planned. As can now
be understood, the DTTL method achieves a simplified and lower cost
well construction casing program. The DTTL method is applicable for
land, shallow water, and deep water prospects. The DTTL method
allows for a higher safety factor than prior art conventional
methods. The MMS requires at least a 200% safety factor on pressure
ratings of all surface equipment. The DTTL method gets to TD with
the deepest and largest open-hole possible for reservoir access.
Simply stated, the DTTL method is faster, cheaper and better than
the conventional or CBHP MPD methods.
[0067] High Pressure Rotating Control Device
[0068] FIG. 6 is a prior art pressure rating graph for the prior
art Weatherford Model 7800 RCD that shows wellbore pressure in
pounds per square inch (psi) on the vertical axis, and RCD
rotational speed in revolutions per minute (rpm) on the horizontal
axis. The maximum allowable wellbore pressure without exceeding
operational limits for the prior art RCD is 2500 psi for rotational
speeds of 100 rpm or less. The maximum allowable pressure decreases
for higher rotational speeds. Weatherford also manufactures an
active seal RCD, RBOP 5K RCD with 7 inch ID, which has a maximum
allowable stripping pressure of 2500 psi, maximum rotating pressure
of 3500 psi, and maximum static pressure of 5000 psi. The pressure
sharing RCDs shown in FIGS. 7 to 17B allow for a much higher
pressure rating both in the static and dynamic conditions than the
prior art RCDs. These pressure sharing RCDs will allow a large
number of tool joints to be stripped out under high pressure
conditions with greater sealing element performance
capabilities.
[0069] While pressure sharing RCD systems are shown in FIGS. 7 to
17B, embodiments other than those shown are also contemplated.
Turning to FIG. 7, RCD, generally indicated at 100, has an inner
member 102 rotatable relative to an outer member 104 about bearing
assembly 106. A first sealing element 110 and a second sealing
element 120 are attached so as to rotate with inner member 102.
Sealing elements (110, 120) are passive stripper rubber seals.
First cavity 132 is defined by inner member 102, drill string DS,
first sealing element 110, and second sealing element 120. A first
sensor 130 is positioned in first cavity 132. A second sensor 140
is positioned in housing 122 and a third sensor 141 is positioned
in diverter housing 123. Sensors (130, 140, 141), like all other
sensors in all embodiments shown in FIGS. 7 to 17B, may at least
measure temperature and/or pressure. Additional sensors and
different measured values, such as rotation speed RPM, are also
contemplated for all embodiments shown in FIGS. 7 to 17B. It is
contemplated that sensors fabricated to tolerate for high
pressure/high temperature geothermal drilling, with methane
hydrates may be used in the cavities. Sensors (130, 140, 141), like
all other sensors in all embodiments shown in FIGS. 7 to 17B, may
be hard wired for electrical connection with a programmable logic
controller ("PLC"), such as PLC 154 in FIG. 7. It is also
contemplated that the connection for all sensors and all PLCs shown
in all embodiments in FIGS. 7 to 17B may be wireless or a
combination of wired and wireless. Sensors may be embedded within
the walls of components and fitted to facilitate easy removal and
replacement.
[0070] PLC 154 is in electrical connection with a positive
displacement pump 152. It is also contemplated that the connection
for all pumps and all PLCs shown in all embodiments in FIGS. 7 to
17B may be wired, wireless or a combination of wired and wireless
and the pumps could be positive displacement pumps. Pump 152 is in
fluid communication with fluid source 150. The fluid source 150
could include fluid from take off lines TO, as shown in FIGS. 1 and
2. Pump 152 is in fluid communication with first cavity 132 through
influent line 134 and a sized influent port 135 in inner member
102. Optional effluent line 136 is in fluid communication with
first cavity 132 through a sized effluent port 137 in inner member
102. If desired, line 136, or any other line discussed herein,
could include a sized orifice or a valve to control flow. Based
upon information received from sensors (130, 140, 141), PLC 154 may
signal pump 152 to communicate a change in the pressurized fluid to
first cavity 132 to provide a predetermined fluid pressure P2 to
first cavity 132 to change the differential pressure between the
fluid pressure P1 in the housing 122 and the predetermined fluid
pressure P2 in first cavity 132 on first sealing element 110. It is
contemplated that the predetermined fluid pressure P2 may be
changed to be greater than, less than, or equal to P1. It is
contemplated that the cavity 132 could hold pressure P2 that is in
the range of 60-80% of the pressure P1 below element 110. However,
any reduction of differential pressure will be beneficial and an
improvement. The predetermined fluid pressure P2 may be calculated
by PLC 154 using a number of variables, such as pressure and
temperature readings from sensors 140, 141. These variables could
be weighted, based on location of the sensor. As is now understood
fluid may be circulated in, into and out of first cavity 132 or
bullheaded. Likewise, fluid may be circulated, into and out of in
all cavities of all embodiments shown in FIGS. 7 to 17B or
bullheaded.
[0071] For all embodiments of the invention, the PLC, like PLC 154
in FIG. 7, may allow adjustable calculations of differential
pressure sharing and supplying RCD cavity fluid. As will be
discussed in detail below, a choke valve may receive from the PLC
set points and the ratio of the shared pressure determined by the
wellbore pressure in keeping with the pressure rating of the RCD.
During operations, the commands of the PLC to the pressure sharing
choke valve may be variable, such as to change the ratio of sharing
to compensate for a sealing element that may have failed. The PLC
may send hydraulic pressure to adjust the choke valve. The PLC may
also signal the choke valve electrically. It is contemplated that
there may be a dedicated hydraulic pump and manifold system to
control the choke valve. It is further contemplated that a
proportional relief valve may be used, and may be controllable with
the PLC.
[0072] As can now be understood, RCD 100 and the pressure sharing
RCD system of FIG. 7 allow for pressure sharing to reduce the
differentiated pressure applied to the first sealing element 110
exposed directly to the wellbore pressure in the housing 122. The
pressure differential across first sealing element 110, which for a
prior art RCD would be substantially the wellbore pressure in the
housing 122, may be reduced so that some of the pressure is shared
with second sealing element 120. In a similar manner, all
embodiments in FIGS. 8 to 17B provide for pressure sharing to
reduce the pressure differential across the first sealing element
that is exposed directly to the wellbore pressure. Other sealing
elements may be used to further "share" some of the pressure with
the first sealing element. This is accomplished by pressurizing the
additional cavities in those embodiments. When the cavity pressure
is different than the pressure across the sealing element
immediately below, then there will be pressure sharing with that
sealing element. When the cavity pressure is greater than the
pressure that the sealing element immediately below is subjected
to, there may be flushing or "burping" through the sealing element
via counteracting the sealing element's stretch-tightness and the
cavity pressure below the sealing element.
[0073] Returning to FIG. 7, an optional first upper conduit 142 and
second lower conduit 146 allow for pressurized flow of fluids,
shown with arrows (144, 145, 148) to cool first sealing element
110. The pressurized flow of fluids (144, 145, 148) may also shield
first sealing element 110 from cuttings in the drilling fluid and
hot returns from the wellbore in housing 122. It is contemplated
that RCD 100, as well as all other RCD embodiments shown in FIGS. 8
to 17B, may have a pressure rating substantially equal to a BOP
stack pressure rating.
[0074] It is contemplated for all embodiments that the fluid to a
cavity may be a liquid or a gas, including, but not limited to,
water, steam, inert gas, drilling fluid without cuttings, and
nitrogen. A cooling fluid, such as a refrigerated coolant or
propylene glycol, may reduce the high temperature to which a
sealing element may be subjected. It may lubricate the throat and
the nose of the passive sealing element, and flush and clean the
sealing surfaces of any scaling element that would otherwise be in
contact with the tubular, such as a drill string. It may also cool
the RCD inner member, such as inner member 102 in FIG. 7, and
assist in removing some frictional heat. A nitrogen pad in a cavity
that can be "burped" into the below wellbore may be beneficial when
drilling in sour formations. It is contemplated for all embodiments
that a gas may be injected into a cavity through a gas expansion
nozzle or a refrigerant orifice.
[0075] It is also contemplated that a single pass of a gas may be
made into a cavity at a pressure that is greater, such as by 200
psi, than the pressure below the lower sealing element of the
cavity. Alternatively, a single pass of chilled liquid or cuttings
free drilling fluid may be made into a cavity at a greater pressure
than the pressure below the lower sealing element of the cavity.
Single-pass fluids that "burp" downward through the lower sealing
element of the cavity may be deposited into the annulus returns via
the lowest sealing element. A single-pass fluid, such as cuttings
free drilling fluid, that burps downward may provide lubrication
and/or cooling between the annular sealing element and drill
string, as well as off-setting some of the pressure below. This may
increase sealing element life.
[0076] It is contemplated that first sealing element 110, as well
as all sealing elements in all other embodiments shown in FIGS. 7
to 17B, may be allowed to pass a cavity fluid, including, but not
limited to, nitrogen. Returning to FIG. 7, second sealing element
120 may be removed and/or replaced from above while leaving first
sealing element 110 in position in the housing 122. Removal of
either sealing element may be necessary for inspection, repair, or
replacement. Alternatively, RCD 100 may be removed using latch 139
of single latching mechanism 141, and sealing elements (110, 120)
thereafter removed. Single and double latching mechanisms for use
with RCD docketing stations are proposed in US Pub. Nos. US
2006/0144622A1 US 2008/0210471A1, which are hereby incorporated by
reference for all purposes in their entirety and assigned to the
assignee of the present application. It is contemplated that all
embodiments may use latching mechanisms and a docketing station,
such as proposed in the '622 and '471 publications.
[0077] Sealing Elements
[0078] As is known, passive sealing elements, such as first sealing
element 110 and second sealing element 120, may each have a
mounting ring MR, a throat T, and a nose N. The throat is the
transition portion of the stripper rubber between the nose and the
metal mounting ring. The nose is where the stripper rubber seals
against the tubular, such as a drill string, and stretches to pass
an obstruction, such as tool joints. The mounting ring is for
attaching the sealing element to the inner member of the RCD, such
a inner member 102 in FIG. 7. At high differential pressure, the
throat, which unlike the nose does not have support of the tubular,
may extrude up towards the inside diameter of the mounting ring.
This may typically occur when tripping out under high pressure. A
portion of the throat inside diameter may be abraded off, usually
near the mounting ring, leading to excessive wear of the sealing
element. For use with the DTTL method, it is contemplated that the
throat profile may be different for each tubular size to minimize
extrusion of the throat into the mounting ring, and/or to limit the
amount of deformation and fatigue before the tubular backs up the
throat. For the DTTL method, it is contemplated that the mounting
ring will have an inside diameter most suitable for pressure
containment for each size of tubular and the obstruction outside
diameter. U.S. Pat. No. 5,901,964 proposes a stripper rubber
sealing element having enhanced properties for resistance to
wear.
[0079] It is contemplated that first sealing element 110 and second
sealing element 120, as well as all sealing elements in any other
embodiment shown in FIGS. 8 to 17B, may be made in whole or in part
from SULFRON.RTM. material, which is available from Teijin Aramid
BV of the Netherlands. SULFRON.RTM. materials are a modified aramid
derived from TWARON.RTM. material. SULFRON material limits
degradation of rubber properties at high temperatures, and enhances
wear resistance with enough lubricity, particularly to the nose, to
reduce frictional heat. SULFRON material also is stated to reduce
hysteresis, heat build-up and abrasion, while improving
flexibility, tear and fatigue properties. It is contemplated that
the stripper rubber sealing element may have para aramid fibers and
dust. It is contemplated that longer fibers may be used in the
throat area of the stripper rubber sealing element to add tensile
strength, and that SULFRON material may be used in whole or in part
in the nose area of the stripper rubber sealing element to add
lubricity. The '964 patent, discussed in the Background of the
Invention, proposes a stripper rubber with fibers of TWARON.RTM.
material of 1 to 3 millimeters in length and about 2% by weight to
provide wear enhancement in the nose area. It is contemplated that
the stripper rubber may include 5% by weight of TWARON to provide
stabilization of elongation, increase tensile strength properties
and resist deformation at elevated temperatures. Para amid
filaments may be in a pre-form, with orientation in the throat for
tensile strength, and orientation in the nose for wear resistance.
TWARON and SULFRON are registered trademarks of Teijin Aramid BV of
the Netherlands.
[0080] It is further contemplated that material properties may be
selected to enhance the grip of the scaling element. A softer
elastomer of increased modulus of elasticity may be used, typically
of a lower durometer value. An elastomer with an additive may be
used, such as aluminum oxide or pre-vulcanized particulate
dispersed in the nose during manufacture. An elastomer with a
tackifier additive may be used. This enhanced grip of the sealing
element would be beneficial when one of multiple sealing elements
is dedicated for rotating with the tubular.
[0081] It is also contemplated that the sealing elements of all
embodiments may be made from an elastomeric material made from
polyurethane, HNBR (Nitrile), Butyl, or natural materials.
Hydrogenated nitrile butadiene rubber (HNBR) provides physical
strength and retention of properties after long-term exposure to
heat, oil and chemicals. It is contemplated that polyurethane and
HNBR (Nitrile) may preferably be used in oil-based drilling fluid
environments 160.degree. F. (71.degree. C.) and 250.degree. F.
(121.degree. C.), and Butyl may preferably be used in geothermal
environments to 250.degree. F. (121.degree. C.). Natural materials
may preferably be used in water-based drilling fluid environments
to 225.degree. F. (107.degree. C.). It is contemplated that one of
the stripper rubber sealing elements may be designed such that its
primary purpose is not for sealability, but for assuring that the
inner member of the RCD rotates with the tubular, such as a drill
string. This sealing element may have rollers, convexes, or
replacement inserts that are highly wear resistant and that press
tightly against the tubular, transferring rotational torque to the
inner member. It is contemplated that all sealing elements for all
embodiments in FIGS. 7 to 17B will comply with the API-16RCD
specification requirements. Tripping out under high pressure is the
most demanding function of annular sealing elements.
[0082] The sized port 135 to first cavity 132 in RCD 100 in FIG. 7
may be used for circulating a coolant or lubricant and/or
pressurizing the cavity 132 with inert gas and/or pressurizing the
cavity 132 with different sources of gas or liquids. Likewise, the
access to all of the cavities in all embodiments shown in FIGS. 8
to 17B may be used for circulating or flushing with a coolant or
lubricant and/or pressurizing the cavity with inert gas and/or
pressurizing the cavity with different sources of gas or liquids.
The pressure sharing capabilities of the embodiment in FIG. 7 allow
the RCD 100 to have a higher pressure rating than prior art RCDs.
The pressure sharing RCD system embodiment shown in FIG. 7, as well
as the embodiments shown in FIGS. 8 to 17B, allow for higher
pressure ratings and may be used with the DTTL method discussed
above. In addition to using the high pressure RCDs in the DTTL
method, the RCDs in all embodiments disclosed herein are desirable
when a higher factor of safety is desired for the geologic
prospect. The RCDs in all embodiments disclosed herein allow for
enhanced well control. Some formation pressure environments are
relatively unknown, such as sub-salt. High pressure RCDs allow for
higher safety for such prospects. "Dry holes" have resulted in the
past from not knowing the formation pore pressure, and grossly
overweighting the drilling fluid to be safe, thereby masking
potentially acceptable pay zones at higher oil and gas market
prices.
[0083] Turning to FIG. 8, RCD, generally indicated at 162, has an
inner member 164 rotatable relative to an outer member 168 about
bearing assembly 166. RCD 162 is latchingly attached with latch 171
to housing 173. A first sealing element 160 and a second sealing
element 170 are attached to and rotate with inner member 164. First
sealing element 160 is an active sealing element. As with other
active sealing elements proposed herein, the active sealing element
160 is preferably engaged on a drill string DS, as shown on the
left side of the vertical break line BL, when drilling, and
deflated, as shown at the right side of break line BL, to allow
passage of a tool joint of drill string DS when tripping in or out.
It is also contemplated that the PLC in all the embodiments could
receive a signal from a sensor that a tool joint is passing a
sealing element and pressure is then regulated in each cavity to
minimize load across all the sealing elements. Second sealing
element 170 is a passive stripper rubber sealing element. First
cavity 185 is defined by inner member 164, drill string DS, first
sealing element 160, and second sealing element 170. A first sensor
172 is positioned in first cavity 185. A second sensor 174 is
positioned in diverter housing 188. Sensors (172, 174) may measure
at least temperature and/or pressure. Sensors (172, 174) are in
electrical connection with PLC 176. PLC 176 is in electrical
connection with pump 180. Pump 180 is in fluid communication with
fluid source 182. Pump 180 is in fluid communication with first
cavity 185 through influent line 184 and sized influent port 181
(though shown blocked) in inner member 164. Effluent line 186 is in
fluid communication with first cavity 185 though sized effluent
port 183 in inner member 164. Based upon information received from
sensors (172, 174), PLC 176 may signal pump 180 to communicate a
pressurized fluid to first cavity 185 to provide a predetermined
fluid pressure P2 to first cavity 185. The differential pressure
change is between the fluid wellbore pressure P1 in the housing 188
and the predetermined fluid pressure P2 in first cavity 185 on
first sealing element 160. It is contemplated that P2 may be
greater than, less than, or equal to P1.
[0084] Active sealing element 160 can be in fluid communication
with a pump (not shown) in electrical connection with PLC 176. The
activation of fluid communication between all active sealing
elements (160, 190, 461, 466, 540, 654, 720) by all PLCs in all
embodiments in FIGS. 8, 9, 13A, 13C, 14B, 16A, and 17B may be hard
wired, wireless or a combination of wired and wireless. Fluid can
be supplied or evacuated through port 185 to activate/deflate
sealing element 160.
[0085] A hydraulic power unit (HPU), comprising an electrically
driven variable displacement hydraulic pump, can be used to
energize the sealing element. The pump can be controlled via an
integrated computer controller within the unit. The computer
monitors the input from the control panel and drives the pump
system and hydraulic circuits to control the RCD. The HPU requires
an external 460 volt power supply. This is the only power supply
required for the system. The HPU has been designed for operation in
Class 1, Division 1 hazardous situation.
[0086] The control system has been designed to allow operation in
an automated manner. Once the job conditions have been set on the
control panel, the hydraulic power unit will automatically control
the RCD to meet changes in well conditions as they happen. This
reduces the number of personnel required on the drill floor during
the operation and provides greater safety.
[0087] In FIG. 8, the means for accessing the first cavity 185
allows for pressure sharing and/or circulating coolant or inert
gas. Second sealing element 170 may be removed and/or replaced from
the above while leaving first sealing element 160 in position in
the housing 173. Alternatively, RCD 162 may be removed from housing
173 using latch 171 to obtain access to the sealing elements (160,
170). For the embodiment shown in FIG. 8, as well as all other
embodiments of the invention, a data information gathering system,
such as DIGS, available from Weatherford may be used with the PLC
to monitor and reduce relative slippage of the sealing elements
with the tubular, such as drill string DS. It is contemplated that
real time revolutions per minute (RPM) of the sealing elements may
be measured. If one of the sealing elements is on an independent
inner member and is turning at a different rate than another
sealing element, then it may indicate slippage of one of the
sealing elements with tubular. Also, the rotation rate of the
sealing elements can be compared to the drill string DS measured at
the top drive (not shown) or at the rotary table in the drilling
floor F.
[0088] For all embodiments in FIGS. 7 to 17B, it is contemplated
that passive sealing elements and active sealing elements may be
used interchangeably. The selection of the RCD system and the
number and type of sealing elements may be determined in part from
the maximum expected wellbore pressure. It is contemplated that
passive sealing elements may be designed for maximum lubricity in
the sealing portion. Less frictional heat may result in longer seal
life, but at the expense of tubular rotational slippage due to the
torque required to rotate the inner member of the RCD. It is
contemplated that active sealing elements may be designed with
friction enhancing additives for rotational torque transfer,
perhaps only being energized if rotational slippage is detected. It
is contemplated that one of the annular sealing elements, active or
passive, may be dedicated to a primary function of transferring
rotational torque to the inner member of the RCD. If the grip of
the active sealing elements are enhanced, they may be energized
whenever slippage is noticed, with enough closing pressure to
assure rotation. The active sealing elements may have modest
closing pressure to conserve their life, and have minimal
differential pressure across the seal. For all embodiments, it is
contemplated that the active sealing elements may allow tripping
out under pressure by, among other things, deflating the active
sealing element.
[0089] Turning to FIG. 9, RCD, generally indicated at 191, has an
inner member 192 rotatable relative to an outer member 196 about
bearing assembly 194. A first sealing element 190, a second sealing
element 200, and a third sealing element 210 are attached to and
rotate with inner member 192. First sealing element 190 is an
active sealing element shown engaged on a drill string DS. Second
sealing element 200 and third sealing element 210 are passive
stripper rubber sealing elements. First cavity 198 is defined by
inner member 192, drill string DS, first sealing element 190, and
second sealing element 200. Second cavity 202 is defined by inner
member 192, drill string DS, second sealing element 200, and third
sealing element 210.
[0090] A first sensor 208 is positioned in first cavity 198. A
second sensor 204 is positioned in first conduit 205, which is in
fluid communication with diverter housing 206. PLC 222 is in
electrical connection with first pump 220. First pump 220 is in
fluid communication with fluid source 234. First pump 220 is in
fluid communication with first cavity 198 through first influent
line 224 and sized first influent port 225 in inner member 192.
First effluent line 226 is in fluid communication with first cavity
198 through sized first effluent port 227 in inner member 192. A
third sensor 218 is positioned in first influent line 224. A fourth
sensor 212 is positioned in first effluent line 226. A fifth sensor
238 is positioned in second cavity 202. PLC 222 is in electrical
connection with second pump 228. Second pump 228 is also in fluid
communication with fluid source 234. Second pump 228 is in fluid
communication with second cavity 202 through second influent line
230 and sized second influent port 217 in inner member 192. Second
effluent line 232 is in fluid communication with second cavity 202
through sized second effluent port 219 in inner member 192. A sixth
sensor 216 is positioned in second influent line 230. A seventh
sensor 214 is positioned in second effluent line 232. Active
sealing element 190 pump (not shown) can be in electrical
connection with PLC 222. Fluid can be supplied or evacuated to
active sealing elements chamber 190A to activate/deflate sealing
element 190. Sensors (204, 208, 212, 214, 216, 218, 238) may at
least measure temperature and/or pressure. Sensors (204, 208, 212,
214, 216, 218, 238) are in electrical connection with PLC 222.
Other sensor locations are contemplated for this and all other
embodiments as desired.
[0091] Based upon information received from sensors (204, 208, 212,
214, 216, 218, 238), PLC 222 may signal first pump 220 to
communicate a pressurized fluid to first cavity 198 to provide a
predetermined fluid pressure P2 to first cavity 198 to reduce the
differential pressure between the fluid wellbore pressure P1 in the
diverter housing 206 and the predetermined fluid pressure P2 in
first cavity 198 on first sealing element 190. It is contemplated
that P2 may be greater than, less than, or equal to P1. PLC 222 may
also signal second pump 228 to communicate a pressurized fluid to
second cavity 202 to provide a predetermined fluid pressure P3 to
second cavity 202 to reduce the differential pressure between the
fluid pressure P2 in the first cavity 198 and the predetermined
fluid pressure P3 in second cavity 202 on second sealing element
200. It is contemplated that P3 may be greater than, less than, or
equal to P2. Active sealing element 190 may be pressurized to
increase sealing with drill string DS if the PLC 222 determines
leakage between the tubular and active sealing element 190. Third
sealing element 210 may be removed from above while leaving second
sealing element 200 in position. Second sealing element 200 may
also be removed from above while leaving first sealing element 190
in position. Alternatively, RCD 191 may be removed from single
latching mechanism 223 by unlatching latch 221 to obtain access to
the sealing elements (190, 200, 210).
[0092] In FIG. 10, RCD, generally indicated at 245, has an inner
member 242 rotatable relative to an outer member 246 about bearing
assembly 244. A first sealing element 240 and a second sealing
element 250 are attached to and rotate with inner member 242.
Sealing elements (240, 250) are passive stripper rubber sealing
elements. First cavity 248 is defined by inner member 242, tubular
or drill string DS, first sealing element 240, and second sealing
element 250. Pressure regulator, such as choke valve 268, is in
fluid communication with first cavity 248 through influent line
269B and sized influent port 271 in inner member 242. A first
sensor 256 is positioned in influent line 269B. A second probe
sensor 254 is positioned in diverter housing 252. Sensors (254,
256) may at least measure temperature and/or pressure. Pressure
regulator or choke valve 268, like all pressure regulators or choke
valves in all embodiments shown in FIGS. 10, 11, 12A, 12B, 13A,
13B, 14A, 14B, 15A, 15B, 15C, 16A, 16B, and 17A can be in
electrical connection with a PLC, such as PLC 260 in FIG. 10. As
discussed above, these regulators can be manual, semi automatic or
automatic and hydraulic or electronic. The electrical connection
may be hard wired, wireless or a combination of wired and wireless.
PLC 260 is in electrical connection with first pump 262. First pump
262 is in fluid communication with fluid source 264. First pump 262
is in fluid communication with first cavity 248 through pressure
regulator or choke valve 268 and influent lines 269A, 2698 through
sized influent port 271 in inner member 242. Effluent line 270 is
in fluid communication with first cavity 248 through sized effluent
port 273 in inner member 242. It is contemplated that in applicable
(not an electronic choke valve) embodiments, a PLC will transmit
hydraulic pressure to adjust the choke valve, e.g. setting the
choke valve. Therefore, a dedicated hydraulic pump and manifold
system is contemplated to control the choke valve.
[0093] Based upon information received from sensors (254, 256), PLC
260 may signal first pump 262 to communicate a pressurized fluid to
first cavity 248 to provide a predetermined fluid pressure P2 to
first cavity 248 to reduce the differential pressure between the
fluid wellbore pressure P1 in the diverter housing 252 and the
predetermined fluid pressure P2 in first cavity 248 on first
sealing element 240. It is contemplated that P2 may be greater
than, less than, or equal to P1. Second pump 258 is in fluid
communication with fluid source 264 and electrical connection with
PLC 260. PLC 260 may signal second pump 258 to send pressurized
fluid through first conduit 272 into diverter housing 252. First
conduit 272 and second conduit 276 allow for pressurized flow of
fluids, shown with arrows (274, 278), to cool and clean/flush first
sealing element 240. The pressurized flow (274, 275, 278) also
shields first sealing element 240 from cuttings in the drilling
fluid and hot returns in the diverter housing 252 from the
wellbore. The same or a similar system may be used for all other
embodiments. Other configurations of pressure regulators or choke
valves, accumulators, pumps, sensors, and PLCs are contemplated for
FIG. 10 and for all other embodiments shown in FIGS. 7 to 17B.
[0094] Turning to FIG. 11, RCD, generally indicated at 282, has an
inner member 284 rotatable relative to an outer member 288 about
bearing assembly 286. A first sealing element 280, a second sealing
element 290, and a third sealing element 300 are attached to and
rotate with inner member 284. Sealing elements (280, 290, 300) are
passive stripper rubber sealing elements. First cavity 292 is
defined by inner member 284, tubular or drill string DS, first
sealing element 280, and second sealing element 290. Second cavity
295 is defined by inner member 284, tubular or drill string DS,
second sealing element 290, and third sealing element 300.
[0095] A first sensor 296 is positioned in first cavity 292. A
second sensor 298 is positioned in the diverter housing 294. First
PLC 302 is in electrical connection with first pump 304. First pump
304 is in fluid communication with first fluid source 322. First
pump 304 is in fluid communication with first cavity 292 through
first pressure regulator, such as choke valve 306, first influent
lines 308A, 308B, and first sized influent port 309 in inner member
284. First effluent line 310 is in fluid communication with first
cavity 292 through first sized effluent port 311 in inner member
284. A third sensor 326 is positioned in first effluent line 310.
First pressure regulator 306 is in fluid communication with
diverter housing 294 through first regulator line 316. A fourth
sensor 314 is positioned in first regulator line 316.
[0096] First PLC 302 is in electrical connection with second pump
324. Second pump 324 is in fluid communication with fluid source
322. Second pump 324 is in fluid communication with second cavity
295 through second pressure regulator 320, second influent lines
321A, 321B, and second sized influent port 323 in inner member 284.
Second effluent line 330 is in fluid communication with second
cavity 295 through second effluent port 327. Fifth sensor 328 is
positioned in second effluent line 330. Second pressure regulator
320 is in fluid communication with first influent line 308B through
second regulator line 318. Sixth sensor 312 is positioned in second
regulator line 318. Sensors (296, 298, 312, 314, 326, 328) may at
least measure temperature and/or pressure. Though sensors 326 and
328 are shown in electrical connection with second PLC 336, sensors
(296, 298, 312, 314, 326, 328) can be in electrical connection with
first PLC 302. Based upon information received from sensors (296,
298, 312, 314, 326, 328), first PLC 302 may signal first pump 304
to communicate a pressurized fluid to first cavity 292 to provide a
predetermined fluid pressure P2 to first cavity 292 to reduce the
differential pressure between the fluid pressure P1 in the diverter
housing 294 and the predetermined fluid pressure P2 in first cavity
292 on first sealing element 280. It is contemplated that P2 may be
greater than, less than, or equal to P1. First PLC 302 may also
signal second pump 324 to communicate a pressurized fluid to second
cavity 295 to provide a predetermined fluid pressure P3 to second
cavity 295 to reduce the differential pressure between the fluid
pressure P2 in the first cavity 292 and the predetermined fluid
pressure P3 in second cavity 295 on second sealing element 290. It
is contemplated that P3 may be greater than, less than, or equal to
P2.
[0097] Third sealing element 300 may be threadedly removed from
above while leaving second sealing element 290 in position. Second
sealing element 290 may be threadedly removed from above while
leaving first sealing element 280 in position. Alternatively, RCD
282 may be unlatched from single latching mechanism 291 by
unlatching latch 293 and removed for access to the sealing elements
(280, 290, 300).
[0098] Second PLC 332 is in electrical connection with sensors 326,
328, first solenoid valve 336 and second solenoid valve 338 and
third pump 334. Third pump 334 is in fluid communication with
second fluid source 340 and lines 310, 330. First accumulator 341
is in fluid communication with line 310, and second accumulator 343
is in fluid communication with line 330. When first pressure
regulator 306 is closed, PLC 332 may signal first valve 336 to open
and third pump 334 to move fluid from second fluid source 340
through line 310 into first cavity 292. Likewise, when second
pressure regulator 320 is closed, second PLC 332 may signal second
valve 338 to open and third pump 334 to move fluid from second
fluid source 340 through line 330 into second cavity 295. It is
contemplated that both pressure regulators 306, 320 may be closed
and both valves 336, 338 open. It is contemplated that the
functions of second PLC 332 may be performed by first PLC 302.
Valves or orifices may be placed in lines 310, 330 to ensure that
the flow moves into first cavity 292 and second cavity 295 rather
than away from them. It is contemplated that the system of third
pump 334, second fluid source 340, and valves 336, 338 may be used
when cuttings free fluid different from fluid source 322, such as a
gas or cooling fluid in a geothermal application, is desired.
[0099] As now can be understood, a "Bare Bones" RCD differential
pressure sharing system could use an existing dual sealing element
design RCD, such as shown in FIG. 10, with the cavity between the
sealing elements having communication with the annulus returns
under the bottom sealing element via a high-pressure line, such as
line 316 shown in FIG. 11. Also, a cuttings filter could be
positioned immediately outside the RCD in the annulus returns line
to filter the annulus returns fluid. An off-the-shelf pressure
relief valve could be substituted in place of the PLC and
adjustable choke valve, e.g., choke valve 306. This substituted
pressure relief valve may be pre-set to open to expose the top
sealing element to full wellbore pressure when the bottom sealing
element senses a predetermined amount of pressure. The top sealing
element may handle some of the wellbore pressure when tripping out
drill string. A reduction of differential pressure would
significantly improve overall performance of the dual sealing
element design RCD and meet AP1 16 RCD "stripping-out-under-dynamic
pressure rating" guidelines. When the wellbore pressure subsides,
the cuttings-free mud of higher pressure in the cavity can be
burped down past (flushing) the sealing surface of the bottom
sealing element. Also, the next tool joint passing thru will
further aid in reducing any bottled up pressure in the cavity.
[0100] Turning to FIGS. 11A and 11B, pressure compensation
mechanisms (350, 370) of the RCD 282 allow for maintaining a
desired lubricant pressure in the bearing assembly at a
predetermined level higher than the pressures surrounding the
mechanisms (350, 370). For example, the upper and lower pressure
compensation mechanisms provide 50 psi additional pressure over the
maximum of the wellbore pressure in the diverter housing 294.
Similar pressure compensation mechanisms are proposed in U.S. Pat.
No. 7,258,171 (see '171 patent FIGS. 26A to 26F), which is hereby
incorporated by reference for all purposes in its entirety and is
assigned to the assignee of the present invention. It is
contemplated that similar pressure compensation mechanisms may be
used with all embodiments shown in FIGS. 7 to 17B. Although only
three sealing elements (280, 290, 300) are shown in FIG. 11, it is
contemplated that there may be more or less and different types of
sealing elements. For all embodiments shown in FIGS. 7 to 17B, it
is contemplated that there may be more or less and different types
of sealing elements than shown to increase the pressure capacity or
provide other functions, e.g. rotation, of the pressure sharing RCD
systems.
[0101] In FIGS. 12A and 12B, second RCD, generally indicated at
390A, is positioned with third housing 454 over first RCD,
generally indicated at 390B, so as to be aligned with tubular or
drill string DS. The combined RCD 390A and RCD 390B is generally
indicated as RCD 390. First RCD 390B has a first inner member 392
rotatable relative to a first outer member 396 about first bearing
assembly 394. A first sealing element 382 and a second sealing
element 384 are attached to and rotate with inner member 392.
Sealing elements (382, 384) are passive stripper rubber sealing
elements. Second RCD 390A has a second inner member 446,
independent of first inner member 392, rotatable relative to a
second outer member 450 about second bearing assembly 448. A third
sealing element 386 and a fourth sealing element 388 are attached
to and rotate with second inner member 446. Sealing elements (386,
388) are also passive stripper rubber sealing elements.
[0102] In first RCD 390B, first cavity 398 is defined by first
inner member 392, tubular or drill string DS, first sealing element
382, and second sealing element 384. Between first RCD 390B and
second RCD 390A, second cavity 452 is defined by the inner surface
of third housing 454 sealed with first RCD 390B and second RCD
390A, tubular or drill string DS, second sealing element 384, and
third sealing element 386. Third cavity 444 is in second RCD 390A,
and is defined by second inner member 446, tubular or drill string
DS, third sealing element 386, and fourth sealing element 388.
[0103] First pressure regulator or choke valve 412, second pressure
regulator or choke valve 424, and third pressure regulator or choke
valve 434 are in fluid communication with each other and the
wellbore pressure in diverter housing 400 through first regulator
line 408 (via influent lines 410A, 428A, 436A) and second regulator
line 407. Pressure regulators (412, 424, 434) are in electrical
connection with PLC 404. A first sensor 406 is positioned in second
regulator line 407. A second sensor 420 is positioned in first
conduit 422 extending from diverter housing 400. First pressure
regulator 412 is in fluid communication with first cavity 398
through first influent line 410B and first sized influent port 415
in first inner member 392. A third sensor 414 is positioned in
first influent line 410B. First effluent line 416 is in fluid
communication with first cavity 398 through first sized effluent
port 417 in first inner member 392. A fourth sensor 418 is
positioned in first effluent line 416. Second pressure regulator
424 is in fluid communication with second cavity 452 through second
influent line 428B and second sized influent port 433 in third
housing or member 454. A fifth sensor 426 is positioned in second
influent line 428B. Second effluent line 430 is in fluid
communication with second cavity 452 through second sized effluent
port 437 in third housing or member 454. A sixth sensor 432 is
positioned in second effluent line 430. Third pressure regulator
434 is in fluid communication with third cavity 444 through third
influent line 436B and third sized influent port 441 in second
inner member 446. A seventh sensor 438 is positioned in third
influent line 436B. Third effluent line 440 is also in fluid
communication with third cavity 444 through third sized effluent
port 443 in second inner member 446. An eighth sensor 442 is
positioned in third effluent line 440. A ninth probe sensor 402 is
positioned in diverter housing 400.
[0104] The nine sensors (402, 406, 414, 418, 420, 426, 432, 438,
442) may at least measure temperature and/or pressure. Sensors
(402, 406, 414, 418, 420, 426, 432, 438, 442) are in electrical
connection with PLC 404. The connection may be hard wired, wireless
or a combination of wired and wireless. Based upon information
received from sensors (402, 406, 414, 418, 420, 426, 432, 438,
442), PLC 404 may signal pressure regulators (412, 424, 434) so as
to provide desired respective pressures (P2, P3, P4) in the first
cavity 398, second cavity 452, and third cavity 444, respectively,
in relation to each other and the wellbore pressure P1. Fourth
sealing element 388 may be removed from above while leaving third
sealing element 386 in position. Removal of second RCD 390A allows
for removal of first RCD 390B with second sealing element 384 and
first sealing element 382. Alternatively, after the second RCD 390A
is removed, second sealing element 384 may be removed from above
while leaving first sealing element 382 in position. Alternatively
to, or in some combination with the above, RCDs (390A, 390B) may be
removed for access to all of the sealing elements. Second RCD 390A
is latchingly attached with third housing 454 by double latch
mechanism 427. Double latch mechanism upper inner latch 421 may be
unlatched to remove RCD 390A. Double latch mechanism lower outer
latch 423 may be used to unlatch double latch mechanism 427 from
third housing 454 with or without the RCD 390A. First RCD 390B may
be unlatched from single latch mechanism 431 using second housing
latch 429. A single and double latch mechanism is proposed in
greater detail in US Pat. No. 7,487,837. Third housing 454 is
bolted with second housing 453, and second housing 453 is bolted
with first or diverter housing 400. Although only two independent
RCDs (390A, 390B) are shown in FIGS. 12A and 12B, it is
contemplated that there may be more or less RCDs and more or less
and different types of sealing elements. As can be understood from
FIGS. 12A and 12B, more than two RCDs, may be stacked in series to
create more cavities and more potential for pressure sharing,
thereby increasing the pressure rating of the stacked combined RCD,
such as RCD 390.
[0105] Turning to FIGS. 13A, 13B and 13C, RCD, generally indicated
as 460, is positioned clamped or bolted in housings (518, 520, 522)
over independent active sealing element 461, which is shown engaged
on tubular or drill string DS. RCD 460 has a common inner member
470 rotatable relative to a first outer member 474 and second outer
member 475 about first bearing assemblies 472 and second bearing
assemblies 477. A first sealing element 462, second sealing element
464, third sealing element 466, and fourth sealing element 468 are
attached to and rotate with inner member 470. Sealing elements
(462, 464, 468) are passive stripper rubber sealing elements. Third
sealing element 466 is an active sealing element, and is shown
engaged on tubular or drill string DS.
[0106] First cavity 476 is defined by second housing or member 516,
third housing or member 518, tubular or drill string DS,
independent active sealing element 461, and first sealing element
462. Within RCD 460, second cavity 478 is defined by inner member
470, tubular or drill string DS, first sealing element 462, and
second sealing element 464. Third cavity 480 is defined by inner
member 470, tubular or drill string DS, second sealing element 464,
and third sealing element 466. Fourth cavity 490 is defined by
inner member 470, tubular or drill string DS, third sealing element
466, and fourth sealing element 468.
[0107] First pressure regulator or choke valve 498, second pressure
regulator or choke valve 500, third pressure regulator or choke
valve 502, and fourth pressure regulator or choke valve 504 are in
fluid communication with each other and the wellbore pressure P1
through first regulator line 496 (via influent lines 508A, 510A,
512A, 514A) and second regulator line 497. Pressure regulators
(498, 500, 502, 504) are in electrical connection with PLC 506. A
first probe sensor 491 is positioned in the diverter housing 515. A
second sensor 492 is positioned in first cavity 476. First pressure
regulator 498 is in fluid communication with first cavity 476
through first influent line 508B and first sized influent port 509
in inner member 470. A third sensor 530 is positioned in second
cavity 478. Second pressure regulator 500 is in fluid communication
with second cavity 478 through second influent line 510B and second
sized influent port 511 in inner member 470. A fourth sensor 532 is
positioned in third cavity 480. Third pressure regulator 502 is in
fluid communication with third cavity 480 through third influent
line 512B and third sized influent port 513 in inner member 470. A
fifth sensor 534 is positioned in fourth cavity 490. Fourth
pressure regulator 504 is in fluid communication with fourth cavity
490 through fourth influent line 514B and fourth sized influent
port 517 in inner member 470.
[0108] Sensors (491, 492, 530, 532, 534) may at least measure
temperature and/or pressure. Sensors (491, 492, 530, 532, 534) are
in electrical connection with PLC 506. Based upon information
received from sensors (491, 492, 530, 532, 534), PLC 506 may signal
pressure regulators (498, 500, 502, 504) so as to provide desired
pressures (P2, P3, P4, P5) in the first cavity 476, second cavity
478, third cavity 480, and fourth cavity 490, respectively, in
relation to each other and the wellbore pressure P1. Pumps (not
shown) for active sealing elements (461, 466) are in electrical
connection with PLC 506. Either one of active sealing elements
(461, 466) or both of them may be pressurized to reduce slippage
with the tubular or drill string DS if the PLC 506 indicates
rotational difference between RCD 460 and independent sealing
elements 461. Fourth sealing element 468 may be removed from above
without removing any sealing element below it. Third sealing
element 466 may thereafter be removed without removing the sealing
elements below it, and second sealing element 464 may be removed
without removing first sealing element 462. Alternatively, RCD 460
may be removed by unlatching first latch member 473 and second
latch member 479. After RCD 460 is removed, latch member 462 can be
unlatched and independent sealing element 461 may be removed.
[0109] First or diverter housing 515 and second housing 516 are
bolted together, as are third housing 518 and fourth housing 520.
However, second housing 516 and third housing 518 are clamped
together with clamp 519A, and fourth housing 520 and fifth housing
522 are clamped with clamp 519B. Other alternative configurations
and attachment means, as are known in the art, are contemplated.
Clamps 519A and 519B may be an automatic clam shell clamping means,
such as proposed in U.S. Pat. No. 5,662,181, which is incorporated
herein by reference for all purposes in its entirety and is
assigned to the assignee of the present invention. It is
contemplated that a clamp like clamps 519A and 519B may be used in
all embodiments, including where bolts are used to connect
housings. Clamps allow for the housings, such as fifth housing 522
in FIG. 13A, to be remotely disassembled so as to obtain access to
or remove a sealing element, such as sealing element 464 in FIG.
13B. Likewise clamp 519A can be unclamped to obtain access to or
remove independent active sealing element 461.
[0110] As with other active sealing elements proposed herein, the
active sealing elements 466, 461 are preferably engaged on a drill
string DS when drilling and deflated to allow passage of a tool
joint of drill string DS when tripping in or out. It is also
contemplated that the PLC in all the embodiments could receive a
signal from a sensor that a tool joint is passing a sealing element
and pressure is then regulated in each cavity to inflate or deflate
the respective active sealing element to minimize load across all
the respective active sealing elements. As now can be better
understood, the pressure regulators 498, 500, 502 and 504 can be
controlled by PLC 506 to reduce wear on selected sealing elements.
For example, when tripping out, the PLC automatically, or the
operator could manually, deflate the active sealing elements 461,
466 so that cavity 476 pressure P2 would be equal to wellbore
pressure P1. PLC 506 could then signal pressure regulator 500 to
increase the pressure P3 in cavity 478 so that pressure P3 is equal
to or greater than pressure P2. With pressure P3 greater than P2,
it is contemplated that passive stripper rubber sealing element 462
would open/expand with less wear when a tool joint engages the nose
of the sealing element 462 to begin to pass therethrough or to be
stripped out. Furthermore, the pressure P4 in cavity 480 could be
controlled by pressure regulator 502 so that both pressures P4 and
P5, since active sealing element 466 is deflated, would be equal to
or greater than pressure P3 to reduce wear on passive stripper
rubber sealing element 464. In this case, passive sealing element
468 would be exposed to the higher pressure differential of
atmospheric pressure resulting from pressures P3 and P4. In other
words, sealing element 468 would be the sacrificial sealing element
to enhance the life and wearability of the remaining sealing
elements 461, 462, 464, 466.
[0111] Pressure relief solenoid valve 494 is sealingly connected
with conduit 493 that is positioned across from conduit 497.
Pressure relief valve 494 and conduit 493 are in fluid
communication with diverter housing 515. Valve 494 may be
pre-adjusted to a setting that is lower than the weakest subsurface
component that defines the limit of the DTTL method, such as the
casing shoe LOT or the formation fracture gradient (FIT). In the
event that the wellbore pressure P1 exceeds the limit (including
any safety factor), then valve 494 may open to divert the returns
away from the rig floor. In other words, this valve opening may
also occur if the surface back pressure placed on the wellbore
fluids approaches the weakest component upstream. Alternatively,
fluid could be moved through open valve 494 through conduit 493 and
across housing 515 to conduit 497 to cool and clean independent
sealing element 461.
[0112] Turning to FIGS. 14A and 14B, RCD, generally indicated as
588, is latched with third housing 568, above independent active
sealing element 540, which is shown engaged on tubular or drill
string DS. Third housing 568 is bolted with second housing 566, and
second housing 566 is bolted with first or diverter housing 564.
RCD 588 has an inner member 552 rotatable relative to an outer
member 556 about bearing assembly 554. A first sealing element 542
and second sealing element 544 are attached to and rotate with
inner member 552. First sealing element and second sealing element
(542, 544) are passive stripper rubber sealing elements.
[0113] First cavity 548 is defined by second housing or member 566,
tubular or drill string DS, independent active sealing element 540,
and first sealing element 542. Within RCD 588, second cavity 550 is
defined by inner member 552, tubular or drill string DS, first
sealing element 542, and second sealing element 544. First pressure
regulator or choke valve 570 and second pressure regulator or choke
valve 574 are in fluid communication with each other and the
diverter housing 564 through first regulator line 578 (via influent
lines 572A, 576A) and second regulator line 580. Pressure
regulators (570, 574) are also in fluid communication with an
accumulator 586. Accumulator 586, as well as all other accumulators
as shown in all other embodiments in FIGS. 14A to 17B, may
accumulate fluid pressure for use in supplying a predetermined
stored fluid pressure to a cavity, such as first cavity 548 and
second cavity 550 in FIGS. 14A and 14B. Accumulators may be used
with all embodiments to both compensate or act as a shock absorber
for pressure surges or pulses and to provide stored fluid pressure
as described or predetermined. Pressure surges may occur when the
diameter of the drill string DS moved through the sealing element
changes, such as for example the transition from the drill pipe
body to the drill pipe tool joint. The change from the volume of
the drill pipe body to the tool joint in the pressurized cavity may
cause a pressure surge or pulse of the pressurized fluid for which
the accumulator may compensate. Pressure regulators (570, 574) are
in electrical connection with PLC 584. A first sensor 558 is
positioned in the diverter housing 564. A second sensor 560 is
positioned in first cavity 548. First pressure regulator 570 is in
fluid communication with first cavity 548 through first influent
line 572B and first sized influent port 573 in second housing 566.
A third sensor 562 is positioned in second cavity 550. Second
pressure regulator 574 is in fluid communication with second cavity
550 through second influent line 576B and second sized influent
port 577 in inner member 552.
[0114] Sensors (558, 560, 562) may at least measure temperature
and/or pressure. Sensors (558, 560, 562) are in electrical
connection with PLC 584. Based upon information received from
sensors (558, 560, 562), PLC 584 may signal pressure regulators
(570, 574) so as to provide desired pressures (P2, P3) in the first
cavity 548 and second cavity 550, respectively, in relation to each
other and the wellbore pressure P1. Solenoid valve 582 is
positioned between the juncture of first regulator line 578 and
second regulator line 580 and valve line 587. Solenoid valve 582 is
in electrical connection with PLC 584. Based upon information
received from sensors (558, 560, 562), PLC 584 may signal pressure
solenoid valve 582 to open to relieve drilling fluid wellbore
pressure from diverter housing 564 and signal the regulators (570,
574) to open/close as is appropriate. The pump (not shown) for
independent active sealing element 540 is in electrical connection
with PLC 584. Pressure to chamber 540A can be increased or
decreased by PLC 584 to compensate for slippage, for example of
sealing element 540 relative to rotation of inner member 552. Third
sealing member 544 may be removed from above without removing the
sealing members below it, and second sealing member 542 may be
removed after removing RCD 588. First independent active sealing
member 540 may be removed from above after removal of RCD 588. A
single latching mechanism having latch member 568A is shown for
removal of RCD 588 while a double latching mechanism having latch
members 541A, 541B is provided for sealing element 540.
[0115] In FIGS. 15A, 15B and 15C, RCD, generally indicated as 590,
is positioned in a unitary diverter housing 591. Tubular or drill
string DS is positioned in RCD 590. RCD 590 has a common inner
member 600 rotatable relative to a first outer member 604, second
outer member 606 and third outer member 610 about a first bearing
assembly 602, second bearing assembly 608 and third bearing
assembly 612. A first sealing element 592, second sealing element
594, third sealing element 596, and fourth sealing element 598 are
attached to and rotate with inner member 600. Sealing elements
(592, 594, 596, 598) are passive stripper rubber sealing
elements.
[0116] First cavity 618 is defined by inner member 600, tubular or
drill string DS, first sealing element 592, and second sealing
element 594. Second cavity 620 is defined by inner member 600,
tubular or drill string DS, second sealing element 594, and third
sealing element 596. Third cavity 622 is defined by inner member
600, tubular or drill string DS, third sealing element 596, and
fourth sealing element 598.
[0117] First pressure regulator or choke valve 630, second pressure
regulator or choke valve 634, and third pressure regulator or choke
valve 638 are in fluid communication with each other and the
wellbore pressure P1 in the lower end of diverter housing 591
through first regulator line 642 (via influent lines 632A, 636A,
640A) and second regulator line 644. Pressure regulators (630, 634,
638) are in electrical connection with PLC 646. A first probe
sensor 616 is positioned in the lower end of diverter housing 591.
A second sensor 624 is positioned in first cavity 618. First
pressure regulator 630 is in fluid communication with first cavity
618 through first influent line 632B and first sized influent port
633 in inner member 600. A third sensor 626 is positioned in second
cavity 620. Second pressure regulator 634 is in fluid communication
with second cavity 620 through second influent line 636B and second
sized influent port 637 in inner member 600. A fourth sensor 628 is
positioned in third cavity 622. Third pressure regulator 638 is in
fluid communication with third cavity 622 through third influent
line 640B and third sized influent port 641 in inner member
600.
[0118] Sensors (616, 624, 626, 628) may at least measure
temperature and/or pressure. Sensors (616, 624, 626, 628) are in
electrical connection with PLC 646. Other sensor configurations are
contemplated for FIG. 15A-15C and for all other embodiments. Based
upon information received from sensors (616, 624, 626, 628), PLC
646 may signal pressure regulators (630, 634, 638) so as to provide
desired pressures (P2, P3, P4) in the first cavity 618, second
cavity 620, and third cavity 622, respectively, in relation to each
other and the wellbore pressure P1. Fourth sealing member 598 may
be removed from above without removing sealing members below it
using latch 600A, third sealing member 596 may also be removed
without removing the sealing members below it using latch 600B.
Once the fourth sealing element is removed, the second sealing
member 594 may be removed without removing first sealing member
592. First sealing member 592 may be removed with inner member 600
using latch. 600C.
[0119] The pressure regulators 630, 634, 638 could be controlled by
PLC 646 so that the two lower stripper rubber sealing elements 592,
594 would experience high wear. In this case, pressure P2 would be
less than, perhaps one half of, the pressure P1 and pressure P3
would be less than, perhaps one-quarter of, pressure P1. This high
differential pressure across sealing elements 592, 594 would cause
the sealing elements 592, 594 to experience higher wear when the
drill string DS and its tool joints are tripped out of the well. As
a result, pressure P4 in cavity 622 could be regulated at less than
one-quarter of the pressure P1 so that the differential pressure
across passive sealing elements 596, 598 is reduced or mitigated.
In summary, upon tripping out sacrificial passive stripper rubber
sealing elements 592, 594 would experience higher wear and
protected passive stripper rubber sealing elements 596, 598 would
experience less wear, thereby increasing their wearability for when
drilling ahead.
[0120] Turning to FIG. 16A and 16B, RCD, generally indicated as
651, is positioned above diverter housing 666. Tubular or drill
string DS is positioned in RCD 651. RCD 651 has a common inner
member 656 rotatable relative to a first outer member 660 about a
first bearing assembly 658 and second bearing assembly 664. A first
sealing element 650, second sealing element 652, and third sealing
element 654 are attached to and rotate with inner member 656. First
sealing element 650 and second sealing element 652 are passive
stripper rubber sealing elements. Third sealing element 654 is an
active sealing element. First cavity 668 is defined by inner member
656, tubular or drill string DS, first sealing element 650, and
second sealing element 652. Second cavity 670 is defined by inner
member 656, drill string DS, second sealing element 652, and third
sealing element 654.
[0121] First pressure regulator or choke valve 678 and second
pressure regulator or choke valve 696 are in fluid (via influent
lines 680A, 698A) communication with each other and the wellbore
pressure P1 in diverter housing 666 through first regulator line
692 and second regulator line 694. Pressure regulators (678, 696)
are in electrical connection with PLC 690. First accumulator 672,
second accumulator 674 and third accumulator 676 are in fluid
communication with first regulator line 692 and the wellbore
pressure P1. Accumulators (672, 674, 676) operate as discussed
above. Solenoid valve 671 is in fluid communication with first
regulator line 692, second regulator line 694, and accumulator 672
and operates as discussed above. A first probe sensor 710 is
positioned in the diverter housing 666 for measuring wellbore
pressure P1 and temperature. A second sensor 688 is positioned in
first influent line 680B. First pressure regulator 678 is in fluid
communication with first cavity 668 through first influent line
680B and first-sized influent port 682 in inner member 656. First
effluent line 686 is in fluid communication with first cavity 668
through first-sized effluent port 684 in inner member 656. Second
pressure regulator 696 is in fluid communication with second cavity
670 through second influent line 69813 and second sized influent
port 702 in inner member 656. A third sensor 700 is positioned in
second influent line 698B. Second effluent line 706 is in fluid
communication with second cavity 670 through second sized effluent
port 704 in inner member 656.
[0122] Sensors (688, 700, 710) may at least measure temperature
and/or pressure. Sensors (688, 700, 710) are in electrical
connection with PLC 690. Based upon information received from
sensors (688, 700, 710), PLC 690 may signal pressure regulators
(678, 696) so as to provide desired pressures (P2, P3) in the first
cavity 668 and second cavity 670, respectively, in relation to each
other and the wellbore pressure P1. Pump (not shown) for active
sealing element 654 is in electrical connection with PLC 690. PLC
690 may also signal solenoid valve 671 to open or close as
discussed above in detail.
[0123] In FIGS. 17A and 17B, RCD, generally indicated as 726, is
latched with fourth housing 757, over independent active sealing
element 720, which is shown engaged on tubular or drill string DS.
Fourth housing 757 is bolted with third housing 754, third housing
754 is bolted with second housing 753, and second housing 753 is
latched using latch 753A with first or diverter housing 751. RCD
726 has an inner member 734 rotatable relative to an outer member
738 about bearings 736. A first sealing element 722 and second
sealing element 724 are attached to and rotate with inner member
734. Sealing elements (722, 724) are passive stripper rubber
sealing elements.
[0124] First cavity 730 is defined by third housing or member 754,
tubular or drill string DS, independent active sealing element 720,
and first sealing element 722. Within RCD 726, second cavity 732 is
defined by inner member 734, tubular or drill string DS, first
sealing element 722, and second sealing element 724. First pressure
regulator or choke valve 748 and second pressure regulator or choke
valve 756 are in fluid communication with each other and the
wellbore pressure P1 in diverter housing 751 through first
regulator line 744 (via influent lines 750A, 758A) and second
regulator line 746. Pressure regulators (748, 756) are also in
fluid communication with an accumulator 762. Pressure regulators
(748, 756) are in electrical connection with PLC 768. A first
sensor 763 is positioned in the diverter housing 751. A second
sensor 764 is positioned in first cavity 730. First pressure
regulator 748 is in fluid communication with first cavity 730
through first influent line 750B and first sized influent port 752
in third housing 754. A third sensor 766 is positioned in second
cavity 732. Second pressure regulator 756 is in fluid communication
with second cavity 732 through second influent line 758B and second
sized influent port 760 in inner member 734.
[0125] Sensors (763, 764, 766) may at least measure temperature
and/or pressure. Sensors (763, 764, 766) are in electrical
connection with PLC 768. Based upon information received from
sensors (763, 764, 766), PLC 768 may signal pressure regulators
(748, 756) so as to provide desired pressures (P2, P3) in the first
cavity 730 and second cavity 732, respectively, in relation to each
other and the wellbore pressure P1. Accumulator 762 is in fluid
communication with first regulator line 744 and therefore the
wellbore pressure P1. Solenoid valve 742 is positioned between the
juncture of first regulator line 744 and second regulator line 746
in valve line 741. Solenoid valve 742 is in electrical connection
with PLC 768. Based upon information received from sensors (763,
764, 766), PLC 768 may signal solenoid valve 742 as discussed
above. Pump (not shown) for active sealing element 720 is also in
electrical connection with PLC 768. The active sealing element 720
may be activated, among other reasons, to compensate for rotational
differences of the drill string DS with the passive sealing
elements. Stabilizer 740 for drill string DS is positioned below
independent active sealing element 720. Drill string stabilizer 740
may be used to retrieve active sealing element 720 after the RCD
726 is removed. It is contemplated that a stabilizer to remove
sealing elements may be used with all embodiments of the
invention.
[0126] Not only may the pressure between a pair of active/passive
sealing elements be adjusted, but also for a configuration in which
an RCD is used within a riser, the pressure above the uppermost
sealing element may be controlled--for example, by selecting the
density and/or the level of fluid within the riser above the RCD.
Depending upon the location of the RCD within the riser (i.e.,
towards the top, in the middle, towards the bottom, etc.), the
selection of fluid type, density and level within the riser above
the RCD may have a significant effect upon the pressure
differential experienced by the uppermost seal of the RCD. Hence,
the annular space within the riser above an RCD presents an
additional "cavity", the pressure within which may also be
controlled to a certain extent.
[0127] A drilling operation utilizing an RCD may comprise several
"phases", each phase presenting different demands upon the
integrity and longevity of an RCD active or passive sealing
element. Such phases may include running a drill string into the
wellbore, drilling ahead while rotating the drill string, drilling
ahead while not rotating the drill string (i.e., when a mud motor
is used to rotate the drill bit), drilling ahead across a
geological boundary into a zone exhibiting higher or lower
pressure, reciprocation of the drill string, pulling a drill string
out of the wellbore, etc. Each of these phases places a different
demand upon the sealing elements of an RCD. For example, running a
drill string into the wellbore may not be particularly detrimental
to the downwardly and inwardly taper of passive stripper rubber
sealing elements; however, such a configuration may be very
detrimental when the drill string is pulled out of the wellbore and
successive upset tool joints are forced upwards past each sealing
element.
[0128] The pressures within each cavity may be controlled during
any phase of the drilling operation, such that adjustment of
pressures within one or more cavities may be tailored to each phase
of the drilling operation. Furthermore, the pressures within each
cavity may be changed occasionally or regularly while a single
phase of the drilling operation is proceeding to spread or "even
out" the demand placed upon one or more sealing elements.
[0129] For example, in operating a multi-seal RCD, the pressures
within one or more cavities may be adjusted such that one
particular sealing element experiences a relatively high
differential pressure, and thereby is considered the "main" sealing
element. This would be the case if one or more additional sealing
elements within the RCD were to be employed as a "reserve" or
protected sealing element, ready to be used as the new "main or
sacrificial" sealing element should the original "main or
sacrificial" sealing element fail. An operator may not wish to
place such a demand on any one sealing element for a prolonged
period, and therefore may periodically choose to adjust the
pressures within the cavities of the RCD such that other sealing
elements within the RCD are utilized as the "main or sacrificial"
sealing element, even though the integrity of the original "main"
sealing element may still be good. In this way, a periodic
assessment of the integrity of each sealing element may be
performed while the RCD is in operation, and the risk of failure of
any one sealing element may be reduced.
[0130] Additionally, adjustment of the pressures within the
cavities may be made according to which of the above phases of the
drilling operation are being conducted. For example, in a
multi-seal RCD, one or more sealing elements may be primarily
employed to contain the wellbore pressure during the drilling
phase--i.e., while the bit is rotating at the bottom of the
wellbore, and the open hole section is being extended. When it is
desired to pull the drill string out of the wellbore, it may be
preferred that one or more other sealing elements be selected for
the duty of primary pressure containment. This is particularly
relevant for those embodiments which include both active and
passive sealing elements. It may be desired to use an active
sealing element only while drilling is progressing, with little or
no demand being placed upon the passive sealing elements. When
pulling the drill string out of the wellbore, the active sealing
element may be de-activated or deflated, and so the remaining
passive sealing elements are selected to contain the wellbore
pressure. Similarly, for those embodiments employing only multiple
passive sealing elements, the pressures within each cavity may be
adjusted such that selected sealing element(s) primarily withstand
wellbore pressure during the drilling phase, whereas other sealing
element(s) primarily withstand wellbore pressure while pulling the
drill string out of the wellbore. In this scenario, the material
and configuration of the material used in each sealing element may
be selected such that those identified for primary use while
pulling the drill string out of the wellbore may be constructed of
a more abrasion-resistant material than those sealing elements
selected for primary use while drilling.
[0131] In a further embodiment, the instantaneous differential
pressure experienced by a sealing element may be controlled
specifically to coincide with the passage of an article, for
example, a tool joint of a drill string, through the sealing
element. For example, while pulling a drill string out of a
wellbore though multiple passive sealing elements, many tool joints
are forced through the sealing elements, which is most detrimental
to the integrity and life of the sealing elements if this occurs
simultaneously while the sealing elements themselves are subject to
withstanding the pressure within the wellbore. Therefore, an
operator may choose to adjust the differential pressure experienced
by a particular sealing element to coincide with the passage of a
tool joint through that sealing element. The pressure within one or
more cavities may be adjusted such that the pressure above a
sealing element is slightly less than, equal to, or greater than
the pressure below the sealing element when the tool joint is being
raised through the sealing element. When the tool joint has passed
through a sealing element and is about to be passed through a
second sealing element, the pressures within each cavity may be
adjusted again such that the conditions under which the tool joint
passed though the first sealing element are replicated for the
second sealing element. In this way, the pulling out of successive
tool joints past each sealing element need not be as detrimental to
the sealing elements as it would have been had this pressure
control not been employed.
[0132] It should be noted that for all situations described above
in which the pressures within the cavities are adjusted according
to the phase of the drilling operation, or the timing of events, or
according to operator selection, the monitoring and adjustment may
be accomplished using manual control, using pre-programmed control
via one or more PLCs, using programmed control to react to a sensor
output (again via a PLC), or by using any combination of these.
[0133] The foregoing disclosure and description of the invention
are illustrative and explanatory thereof, and various changes in
the details of the illustrated apparatus and system, and the
construction and method of operation may be made without departing
from the spirit of the invention.
* * * * *